
DEPARTMENT OF THE INTERIOR 

Franklin K. Lane, Secretary 


Survey 


States Geological 

George Otis Smith, Director 


United 


BULLETIN 653 


ffi SAN JOAQUIN VALLEY, CALIFORNIA 


PRELIMINARY REPORT 


G. SHERBURNE ROGERS 


WASHINGTON 

GOVERNMENT PRINTING 

1917 


OFFICE 


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DEPARTMENT OF THE INTERIOR 

Franklin K. Lane, Secretary 


United States Geological Survey 

George Otis Smith, Director 


Bulletin 653 


CHEMICAL RELATIONS OF THE OIL-FIELD WATERS 
IN SAN JOAQUIN VALLEY, CALIFORNIA 


PRELIMINARY REPORT 


BY 

G. SHERBURNE ROGERS 

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WASHINGTON 

GOVERNMENT PRINTING OFFICE 

1917 











ADDITIONAL COPIES 

OF THIS PUBLICATION MAY BE PROCURED FROM 
THE SUPERINTENDENT OF DOCUMENTS 
GOVERNMENT PRINTING OFFICE ' 
WASHINGTON, D. C. 

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10 CENTS PER COPY 


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CONTENTS. 


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Page. 


Introduction. 5 

Conclusions and recommendations. 5 

Acknowledgments. G 

Need for more analyses. 7 

Location of the oil fields. 8 

San Joaquin Valley. 9 

Geography and drainage. 9 

Geology. 9 

Underground water. 11 

Occurrence of water in the oil fields. 12 

General distribution. 12 

Water sands. 13 

Texture. 13 

Freedom of circulation. 14 

Dry sands. 15 

Relation to the oil. 16 

Physical characteristics. 17 

Head or pressure. 17 

Temperature. 19 

Geologic conditions that influence the composition of water. 20 

General features. 20 

Origin of salt water in rocks. 20 

Relation of geologic structure to distribution of salt water in the oil fields. 23 

General association of salt water and petroleum. 25 

Distribution of water in the oil fields. 26 

Coalinga field. 26 

Lost Hills field. 27 

McKittrick field. 27 

Midway-Sunset field. 28 

Kern River field. 29 

Analysis of water and interpretation of results. 29 

Mineral constituents in water. 29 

Collection of samples. 30 

Chemical analysis. 31 

Determination of constituents. 31 

Statement of analysis. 32 

Reacting values. 35 

Properties of reaction. 37 

Source and statement of analyses in this report. 40 

Classification of the oil-field waters. 41 

Distribution and significance of the constituents. 41 

Alkalies (sodium and potassium). 41 

Alkaline earths (calcium and magnesium). 42 

Sulphate. 43 

Chloride.-. 44 

Carbonate and bicarbonate..*. 44 

Sulphide. 45 

Iron and aluminum. 46 

Silica.-.*. 47 

3 


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4 CONTENTS. 

Classification of the oil-field waters—Continued. 

Distribution and significance of the constituents—Continued. p a ge. 

Other constituents. 47 

Total mineral solids. 47 

Organic and volatile matter. 47 

Criteria for comparison. 48 

Proposed classification. 49 

Composition of the oil-field waters.1. 53 

Description of the types. 53 

General comparison. 53 

Surface water. 55 

Normal ground water. 58 

Shallow water wells. 58 

Oil wells (top water). 58 

Modified ground water. 64 

Altered ground water. 67 . 

Reversed type. 67 

Brine. 71 

Mixed type. 75 

Relations of the types.-_ 77 

Vertical relations.^. 78 

Areal relations. 86 

Variation in chloride. 86 

Relations of the mixed type. 88 

Chemical relations between water and the hydrocarbons. 93 

Alteration of waters by the hydrocarbons. 93 

Nature of alterations. 93 

Reduction of sulphate. 93 

Formation of carbonate. 98 

Production of gases. 100 

Alteration of hydrocarbons by water. 102 

Solubility of petroleum constituents in water. 105 

Value of water analyses to the oil operator. 109 

Summary of conclusions. 113 

Index. 117 


ILLUSTRATIONS. 


Page. 

Figure 1. Diagram showing circulation or stagnation of the water in open and 
closed sand lenses before and after the lenses are penetrated by 
wells. 14 

2. Graphic representation of analysis 31, showing method of deducing 

the properties of a water from its composition.* 39 

3. Diagram illustrating relation of oil-field waters of the meteoric and 

connate types, and their alteration as the oil zone is approached.. 51 

4. Chart showing chemical relations of the oil-field waters. 54 

5. Variation in chemical character of waters from different depths, 

showing alterations by hydrocarbons. 79 

6 . Diagram showing increase in salinity of waters in the northern part 

of the Midway field with distance from the outcrop. 88 

7. Diagram showdng gradation between waters of the mixed type in the 

western part of the Midway-Sunset field and the brines that occur 
at the same general horizon in the deeper territory to the east... 91 










































CHEMICAL RELATIONS OF THE OIL-FIELD WATERS IN 
SAN JOAQUIN TALLEY, CALIFORNIA. 


PRELIMINARY REPORT. 


By G. Sherburne Rogers. 


INTRODUCTION. 

CONCLUSIONS AND RECOMMENDATIONS. 

During the rapid rise of the petroleum industry in the last 50 years 
the geologic occurrence of petroleum has received a great amount of 
study, and the interesting problems involved in its origin and migra¬ 
tion have engaged the attention of many geologists. It has long 
been known that oil and gas are commonly associated with water, 
and the great importance of the water as a physical agent in the migra¬ 
tion of the oil has been recognized in all geologic theories of the 
accumulation of oil. Of the chemical relations between the water 
and the oil, however, we know little, and scientific literature con¬ 
tains only a few references even to the chemical character of the 
waters themselves. Apparently many of the current ideas on this 
subject either are erroneous or can be accepted only with important 
modifications. 

In the oil fields of San Joaquin Valley, Cal., the oil and water are 
found in practically unconsolidated rocks. At most localities several 
water-bearing sands are intercalated in the shales above the oil 
measures, and there is also a water sand a short distance beneath 
them. In some places a water sand occurs in the shale that sepa¬ 
rates the oil sands, and less commonly oil and water have been found 
in the same stratum. In sinking a well through this complex it is 
difficult to prevent the water, which in places is under high head, 
from entering the oil sand, in which event it may drive the oil some 
distance back and so ruin a considerable tract of land. The writer 
studied the physical and chemical relations of the water and oil in 
these fields during the summers of 1914 and 1915. The chief con¬ 
clusions concerning the chemistry of the waters, deduced by him 
from a study of several hundred analyses of water from different 
depths, are as follows: 


5 





6 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


1. Oil-field water is not necessarily salty, as is generally believed, 
and may not be even slightly salty to the taste. The degree of concen¬ 
tration of chloride in such water is governed primarily by local condi¬ 
tions and is not affected by the position of the water in relation to oil. 

2. Sulphate, which predominates in most of the shallow ground 
waters on the west side of San Joaquin Valley, diminishes in amount 
as the oil zone is approached and finally disappears. 

3. The concentration of carbonate increases as the oil zone is 
approached but depends largely on the concentration of chloride. 

4. The horizon, with respect to the oil zone, at which these altera¬ 
tions take place, is different in each field. 

On the basis of these conclusions, which appear to be well grounded, 
at least for the area studied, the following practical suggestions may 
be made: 

In drilling a well in untested territory it may be possible to obtain 
an indication of the presence or absence of oil and gas below by ascer¬ 
taining by analysis whether the sulphate is diminishing and the car¬ 
bonate increasing in the waters successively encountered. In some 
areas a significant change may be detected as much as 1,000 feet 
above the oil; in others the upper limit of alteration may be within 
a few hundred feet of the oil. 

The source of the water in a well that produces a mixture of water 
and oil may be determined, at least in a general way, by studying 
its chemical composition. In the Westside Coalinga field, for exam¬ 
ple, the source of the water may thus be determined rather definitely; 
in the Midway-Sunset field, where the distinctions are less sharp, the 
success of this method will depend largely on the number of authentic 
analyses that are available for comparison. 

In this report the writer aims first to present the evidence on which 
the foregoing conclusions are based and to discuss the interpretation 
of water analyses and their value from the operator’s standpoint, and 
second, to discuss the chemical relations of water and oil in so far 
as present information permits. It is hoped that this preliminary 
presentation will indicate the importance of experimental geochemical 
work on the interaction of the organic constituents of oils and the 
inorganic substances found in the oil-field waters. Enough is known 
already to warrant the belief that systematic experimental work in 
petroleum hydrology will yield results of practical as well as scientific 
value. 

ACKNOWLEDGMENTS. 

The writer wishes to express his appreciation of the assistance and 
cooperation rendered by Mr. R. W. Pack, with whom he was asso¬ 
ciated in a study of the Midway and Sunset fields for the United 
States Geological Survey during the summer of 1914. Dr. Chase 
Palmer and Mr. Herman Stabler, also of the Survey, as authors of 


INTRODUCTION. 


7 


the system of interpretation of water analyses adopted in this report, 
have been freely consulted, and Dr. Palmer in particular has been a 
constant source of help in the study of the chemical relations of water 
and oil. The writer is indebted also to Mr. It. B. Dole for generous 
consultation on some of the problems touching the chemistry of 
natural waters. Dr. Chase Palmer and Mr. S. C. Dinsmore made 
many of the water analyses included in the report. 

Special mention should be made of the unpublished work of Mr. E. 
A. Starke, of the Standard Oil Co., on the chemistry of the waters of 
the California oil fields. Mr. Starke has collected and studied a large 
number of water analyses and reached several years ago many of the 
conclusions that the writer has recently arrived at independently. 
Mr. Starke noted the absence of sulphate in waters associated with 
oil and ascribed it to chemical reaction between the two, and so has 
guided his prospecting to a considerable extent by studying the com¬ 
position of the waters encountered in prospect wells. The special 
thanks of the writer are due Mr. Starke for his free discussion of the 
subject and for the use of some of the analyses included in this report. 

The success of any study of underground conditions in an oil field 
depends on the good will and courtesy of the operators, and the 
writer desires gratefully to acknowledge the support and cooperation 
of all the companies visited. A complete list of those who have 
cheerfully and generously furnished information would include 
practically all the operators in the Coalinga, Midway, and Sunset 
fields, many of whom spent considerable time in assisting in the col¬ 
lection of samples of water for analysis. The following gentlemen 
rendered the writer especially valuable aid: Messrs. B. H. van der 
Linden, M. E. Lombardi, E. G. Gaylord, Paul Paine, M. J. Kirwan, 
W. W. Orcutt, M. L. Requa, T. A. O’Donnell, E. O. Faulkner, W. M. 
Wallace, J. E. Elliot, W. A. Ambrose, F. B. Tough, J. J. Hern, R. D. 
Bush, T. J. Crumpton, W. A. Greer, W. E. Brown, and J. H. Dearin. 

NEED FOR MORE ANALYSES. 

In the course of this investigation more than 50 samples of water have 
been specially analyzed and about 250 analyses, most of them made 
for industrial purposes, have been furnished by the oil companies. 
These have been sufficient, it is believed, to form a fair basis for the 
principles set forth in this paper, but they are inadequate to give 
more than a general idea as to the character of the waters in any par¬ 
ticular locality. In the Westside Coalinga field all the evidence leads 
to the conclusion that conditions are fairly constant, and that even 
with the data at hand it is possible to determine the general horizon 
of a water from its analysis. In the Midway-Sunset field, however, 
the zone of water altered by the oil may in some localities extend 600 
feet above the oil measures, and it is at present impossible to deter- 


8 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


mine whether or not this zone of altered water may be satis! actorily 
subdivided. Even if this differentiation could not be made analyses 
will be of great value in locally correlating the various waters, as, for 
example, in determining whether or not the water produced by two 
neighboring wells is the same. 

It is generally recognized to-day that the problem of preventing 
water from invading the oil sands is one of the gravest problems con¬ 
fronting the oil industry in California. By following the methods sug¬ 
gested in this report a clue can probably be obtained to the source of 
the water that floods a well, a knowledge of which is essential to its 
proper exclusion. These methods are being successfully used by the 
Standard Oil Co. and should prove equally valuable to other 
operators. 

It may be oorne m mind, however, that the work of gathering the 
data must fall on the operators themselves, for it is impossible for 
anyone not constantly on the ground to collect an adequate set of 
samples. An analysis is of little value as a standard for comparison 
unless the position of the water is known, and properly located sam¬ 
ples can usually be taken only while the well is being drilled or 
repaired. The samples need not necessarily be analyzed immediately 
but may be sealed and stored away until their analysis becomes 
desirable. Several of the larger companies have begun to realize 
the value of analyses and are taking samples wherever good ones can 
be obtained. It is well to bear in mind that the trouble and cost of 
collecting a sample and having it analyzed are negligible in compari¬ 
son with the value that the information thus made available may 
later acquire. 

LOCATION OF THE OIL. FIELDS. 

The oil fields of San Joaquin Valley are in Fresno and Kern coun¬ 
ties. The most important fields are on the west side of the valley, 
along the flanks of the Coast Ranges, and extend, with intervening 
unproductive areas, for a distance of 110 miles. The Coalinga field, 
in Fresno County, is the northernmost of the developed fields, and the 
Midway-Sunset field, in Kern County, is the southernmost. The 
Lost Hills and Devils Den districts are roughly halfway between the 
two, and the Belridge and McKittrick fields are between the Devils 
Den and the Midway. The only field on the east side of San Joaquin 
Valley is the Kern River field, which is on the lowest foothills of the 
Sierra Nevada near Bakersfield, about 30 miles northeast of the 
Midway-Sunset field. By far the most important of these fields, 
named in order of age of exploitation, are the Kern River, Coalinga, 
and Midway-Sunset fields. At present, however, the Midway-Sunset 
field is the largest in the State in annual production, and it is followed 
by the Coalinga and the Kern River, in the order named. 


OIL-FIELD WATERS TN SAN JOAQUIN VALLEY, CAL. 9 

SAN JOAQUIN VALLEY. 

GEOGRAPHY AND DRAINAGE. 

San Joaquin Valley, a part of the great and nearly level-floored 
depression which traverses the central part of California, is bounded 
on the east by the Sierra Nevada and on the west by the Coast Ranges. 
San Joaquin River, which directly drains the northern two-thirds of 
this great valley, discharges through Carquinez Strait into San 
Francisco. Bay and thence through the Golden Gate into the Pacific 
Ocean. The southern, more arid third of the valley has no surface 
outlet under normal conditions, and the surface waters accumulate in 
the Buena Vista reservoir, near the Midway-Sunset field, and in the 
depression occupied by Tulare Lake, southeast of Coalinga. The 
streams that drain into the valley from the Sierra Nevada carry 
praotically all the surface water that reaches it, for the streams on 
the west side are shorter and practically dry during the greater part 
of the year. On this account the valley floor is unsymmetric, the 
axis or line of lowest depression lying nearer the western than the 
eastern foothills. 

A considerable portion of the drainage from the mountains sinks 
into the sand and silt of the valley floor and joins the underground 
circulation. As all the drainage from the valley must pass through 
the narrow outlet at Carquinez Strait the underground circulation 
is probably extremely slow. Mendenhall has aptly referred to the 
great central depression of California, of which San Joaquin Valley is 
the southern part, as “canoe-shaped, with only a notch in the rim at 
the straits through which the waters spill.” 1 

GEOLOGY . 2 

It is not the purpose of this report to describe in any detail the 
geology of San Joaquin Valley or of its oil fields, but a brief outline is 
necessary to a proper understanding of the conditions governing the 
chemical character and the flow of the underground water. 

Although San Joaquin Valley is essentially a great structural 
trough filled with valley wash, the geologic conditions on its east and 
west sides present many points of contrast. The east boundary of 
the valley is the Sierra Nevada, which is composed of granites and 
metamorphosed sedimentary and igneous masses of pre-Cretaceous 

1 Mendenhall, W. C., Preliminary report on the ground waters of San Joaquin Valley, Cal.: U. S. Geol. 
Survey Water-Supply Paper 222, p. 25, 1908. 

2 The geology of the oil fields of San Joaquin Valley is more completely described in the following reports: 
Arnold, Ralph, and Anderson, Robert, Geology and oil resources of the Coalinga district, Cal.: U. S. Geol. 
SurveyBull. 398,1910. Arnold, Ralph, and Johnson, H. R., Preliminary report on the McKittrick-Sunset 
oilregion, Kern and San Luis Obispo counties, Cal.: U. S. Geol. Survey Bull. 406,1910. Anderson, Robert, 
Prel imin ary report on the geology and possible oil resources of the south end of the San Joaquin Valley, 
Cal.: U. S. Geol. Survey Bull. 471, pp. 106-136, 1912. Anderson, Robert, and Pack, R. W., Geology and 
oil resources of the west border of the San Joaquin Valley north of Coalinga, Cal.: U. S. Geol. Survey Bull. 
603, 1915. 


\ 




10 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

age. At the loot of the Sierra these rocks are overlain by practically 
unaltered Tertiary sediments, which dip gently to the west and dis¬ 
appear beneath the sand and gravel of the valley proper. These 
Tertiary formations are not everywhere present, but are well devel¬ 
oped in the neighborhood of the Kern River field. The lower of 
the Tertiary formations is made up in part of diatomaceous shale, 
which is probably the source of the oil; the upper division consists 
of coarse sand, gravel, and clay, into which the oil has probably 
migrated, and in which it is now obtained. 

The oldest rocks on the west side of the valley are probably of 
Jurassic age and comprise a series of altered igneous and sedimentary 
rocks. This formation forms the backbone of the Diablo Range 
north of Coalinga and probably extends beneath the surface for 
some distance to the south. It is overlain on the valley side by a thick 
series of Cretaceous shale and sandstone, from the upper part of which 
oil in commercial quantities is produced in the Oil City district of 
the Coalinga field. The Cretaceous is overlain by rocks of Eocene 
and Oligocene (?) (earlier Tertiary) age, above which is a mass of 
sandstone and diatomaceous shale belonging to the middle Tertiary. 
Shale, sandstone, and conglomerate of later Tertiary age (upper 
Miocene and Pliocene) overlie these formations, in most places un- 
conformably, and these are in turn overlain by similar Quaternary 
sediments. The later Tertiary deposits, which are practically un¬ 
consolidated, were probably laid down under alternating marine, 
brackish, and fresh-water conditions; the series as a whole is charac¬ 
terized by many minor unconformities and by the lenticularity of 
its individual beds. 

In the Coalinga district the oil is believed to have formed in the 
Oligocene (?) shale and to have migrated up into overlying beds, 
which are partly middle Tertiary and partly younger. In the 
Temblor Range fields to the £outh most of the oil probably originated 
in the thick beds of diatomaceous shale of middle Tertiary age; 
it is now found in the irregularly stratified rocks of the later Ter¬ 
tiary. As the lower part of these lenticular masses constitutes the 
main oil measures everywhere except in part of the Coalinga field, 
the correlation of individual oil and water sands by a study of the 
well logs is very difficult. 

This whole sedimentary series, resting in what may be considered 
broadly as a great eroded anticline, constitutes the Diablo and 
Temblor ranges. The older rocks, closely folded, form the main 
mountain mass; the younger rocks, more gently folded but dipping 
in general away from the axis, form the lower flanks and foothills. 
The oil-bearing strata outcrop well down at the foot of the range, 
where the prevailing dips are toward the north or northeast at a 
comparatively low angle. In many places, however, these strata 


SAN JOAQUIN VALLEY. 


11 


are affected by one or more minor flexures which run obliquely out 
from the main ranges, and it has been pointed out by Anderson and 
1 ack 1 that all of the oil fields on the west side are associated with 
folds of this kind. In other words, all of these fields lie either on 
such an anticline or in the syncline back of it, or extend over both 
anticline and syncline. The Midway-Sunset field extends over 
several minor folds. The reason for the accumulation of oil only 
under these structural conditions need not be considered here, but 
it is important to note that all of the fields on the west side are 
characterized by this type of structure, for it undoubtedly influences 
the circulation of the oil-field waters. 

UNDERGROUND WATER . 2 

A large proportion of the surface water entering San Joaquin 
Valley sinks below the surface and joins the underground circulation, 
which follows the surface flow in general direction but at a far slower 
rate. The rate of movement of underground water is governed by 
several factors, important among which are the gradient of the slope, 
the shape and size of the materials through which the water must 
flow, and the freedom of the outlet by which it escapes. In San 
Joaquin Valley all these factors militate against rapid flow; the gra¬ 
dient is low, the materials generally fine, and the outlet at Carquinez 
Straits is narrow. As a result of these conditions the ground water 
is under artesian head in a wide belt along the center of the valley. 
Near the north end of the valley the waters are practically ponded 
and the deeper waters are highly mineralized, and even in the southern 
part the main valley circulation probably is abnormally sluggish. 

Owing to the sharp contrast in meteorologic and geologic conditions 
between the east and west sides of the valley the ground waters 
present some interesting chemical variations. As the Sierra is a 
region of moderate rainfall, and as the Temblor and Diablo ranges 
are semiarid, practically all the surface water entering the valley 
is brought down by streams on the east side. As this water is the 
drainage of a region underlain by granites and other relatively in¬ 
soluble silicate rocks, it is low in mineral content and carries chiefly 
carbonates. The west side of the valley, on the other hand, is a 
region of very scanty rainfall, nearly all of which sinks beneath the 
surface before reaching the valley proper and circulates through a 
great series of sedimentary formations. These strata contain a 
large amount of disseminated gypsum and other sulphates, which 

1 Anderson, Robert, and Pack, R. W., Geology and oil resources of the west border of the San Joaquin 
Valley north of Coalinga, Cal.: U. S. Geol. Survey Bull. 603, pp. 116-121, 1915. 

2 For a complete account of the underground waters of San Joaquin Valley, see Mendenhall, W. C., 
Dole, R. B., and Stabler, Herman, Ground water in San Joaquin Valley, Cal.: U. S. Geol. Survey Water- 
Supply Paper 398, 1916. 



12 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

are readily dissolved by the waters leaching through them. The 
waters of the west side, are therefore high in mineral matter and 
predominantly sulphate in character. Dole 1 has shown that an 
intermediate or axial zone may be distinguished near the center of 
the valley, where the waters are characterized principally by their 
high content of alkalies (sodium and potassium). 

The character of ground waters in San Joaquin Valley is, therefore, 
controlled primarily by geologic conditions, and it will be shown that 
in the oil fields local chemical influences have led to the development 
of still other types of water. Broadly speaking, the ground water of 
the valley enters it chiefly from the east side and flows slowly and 
against considerable resistance toward the north. It has been 
suggested that because of these conditions the meteoric water enter¬ 
ing from the Sierra side has produced sufficient hydrostatic head to 
force the oil to the west side of the valley and to trap it under the 
peculiar structural features locally existing there. In other words, a 
flow or pressure across the valley rather than in a longitudinal direc¬ 
tion is postulated. That underground waters have had much to do 
with the accumulation of the oil can not be doubted, and some 
support is lent this view by the fact that the water certainly encounters 
considerable resistance in its normal northerly course. The possi¬ 
bility of lateral pressure must be borne in mind in considering the 
accumulation of the oil, but it may be pointed out that the chemistry 
of the oil-field waters offers little support to this view; that if the 
theory is correct the anomalous position of the Kern River field on 
the east side of the valley must be explained; and that a theory 
involving the transmission of hydrostatic head through 20 to 40 
miles of lenticular materials, and with only a slight initial difference 
in head, involves grave difficulties. 

OCCURRENCE OF WATER IN THE OIL FIELDS. 

GENERAL DISTRIBUTION. 

In considering the ground-water system of the valley as a whole 
it has been tacitly assumed that the water exists as a continuous 
body saturating all the rocks to an indefinite depth. This conception 
is well founded and is valuable in a broad study, although the fact 
that the circulation of the water is confined largely to certain strata 
is of course of great practical importance. The question in which 
layers the water will circulate depends on a variety of factors, most 
of which are well understood. There is no intrinsic difference 
between a water sand and any other sand. 


1 Mendenhall, W. C., Dole, R. B., and Stabler, Herman, op. cit., p. 117. 



OCCURRENCE OF WATER IN OIL FIELDS. 


13 


WATER SANDS. 

Texture .—Water flows most readily through rocks of uniformly 
coarse grain, and hence tends to circulate chiefly in the sandy layers. 1 
The amount and pressure of the water in a sand depends largely on 
local conditions, but if these were uniform water would normally be 
found in greater available quantity and under higher head in coarse 
sand than in tight sand or sandy shale. In other words, the character 
of the rock has much to do with its content of available water, 
which in a thick sandy stratum is usually concentrated in one or 
more “pay streaks” just as oil is concentrated in certain parts of an 
oil sand. 

The rapidity of circulation of the water through a stratum is not, 
however, an index of the amount of water that the rock contains. 
Coarse open sand, through which flow is most rapid, has an average 
pore space or absorptive capacity of 32 to 37 per cent; unsorted or 
tighter sand, of 38 to 42 per cent; and clay, of 44 to 47 per cent. 2 
The important consideration for practical purposes is, however, that 
the sand yields its water readily because mor£ fluid can easily take 
its place, whereas movement is slower in the clay and much of the 
water is probably held by capillary attraction. A sandy shale or a 
tight sand may also contain considerable water which will not be 
apparent in drilling because it escapes too slowly from the bed. If 
all the strata penetrated by an ordinary oil well could be carefully 
examined, those below the ground-water level probably would be 
found to contain more or less water, although the water content of 
certain strata might be far less than the absorptive capacity of the 
rock. Most of the beds, however, are too fine grained to permit 
perceptible movement of the water in them, and consequently most 
of the drainage passes through a few layers. 

It is thought by some drillers that water sands have a peculiar 
texture by which they may be distinguished from oil sands. It is 
variously held that the grains are sharper or more angular, or that 
they are smaller, or that water sand contains grains of mica, whereas 
oil sand does not. Any of these distinctions may be valuable locally, 
and some sands may be traced for a considerable distance by their 
texture and mineral character, but to assume that water sands and 
oil sands are essentially different in grain or mineral composition is to 
overlook entirely the principles governing the movement of water 
and oil. 

1 Slichter, C. S., The motions of underground waters:,U. S. Geol. Survey Water-Supply Paper 67, 1902; 
Field measurements of the rate of movement of underground water: U. S. Geol. Survey Water-Supply 
Paper 140, 1905. 

2 King, F. H., Principles and conditions of the movements of ground water: U. S. Geol. Survey Nine¬ 
teenth Ann. Rept., pt. 2, pp. 209-215, 1899. 




14 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


Freedom of circulation .—Although, the grain of the rocks is an 
important factor in determining which beds the drainage follows, as 
the term “water sand” implies, an equally great factor in lenticular 
material is the freedom of inlet and outlet of the lens itself. It is 
evident that water will not circulate in a bed unless that entering at 
the outcrop can escape at the lower end of the lens, either into another 
lens or through some practicable channel. (See fig. 1.) If the upper 
end is open and the lower end sealed water will accumulate only up 
to the absorptive capacity of the sand, and if the hydrostatic head of 



Figure 1.—Diagram showing circulation or stagnation of the water in open and closed sand lenses 

before and after the lenses are penetrated by wells. 


the water thus trapped is not great enough to force an outlet move¬ 
ment will cease until the pocket is opened by the drill. The structure 
of the rocks may exercise an entirely similar effect in preventing 
circulation, so that water may be trapped in a syncline or a basin. 
If a lens is effectually sealed on all sides there can be no movement 
even when it is penetrated in drilling unless the rock pores are partly 
filled with air or gas under pressure, under which circumstances the 
expansion of the gases may displace some of the water. It is probable 
that most of the so-called water sands in the valley fields fall in one 
of these three classes, which are shown diagrammatically in figure 1. 














































OCCURRENCE OF WATER IN OIL FIELDS. 


15 


DRY SANDS. 

In most well logs an attempt is made to differentiate water sands 
and “dry” sands, the “dry” sands being typically those which 
absorb water instead of yielding it. Under ordinary conditions of 
drilling it is generally necessary to maintain a certain depth of water 
in the drill hole, ranging from a few hundred feet when drilling 
shallow wells by the standard method to the total depth of the hole 
when the rotary method is used. The driller’s characterization of a 
stratum as water sand or dry sand must then depend largely on the 
fluctuation of the water level in the hole. If the water in the sand 
is under high artesian head the water will rise in the drill hole and 
may flow at the surface (fig. 1, C). However, a column of drilling 
water a thousand feet high exerts a pressure of 434 pounds per square 
inch at the bottom of the hole, and this pressure must be counter¬ 
balanced by the hydrostatic pressure in the sand before the water 
level in the drill hole will rise. If the hydrostatic pressure is equal 
to the weight of the column of drilling water no change in level will 
occur, but if the pressure is lower the water level will sink and most 
of the drilling water may be absorbed. Thus sands which rapidly 
absorb most of the drilling water might instead yield a short column 
of water if the drill hole were dry, and if they were pumped might 
prove steady producers. Many such sands have doubtless been 
reported to be dry. This distinction is by no means an academic 
one. Water under low hydrostatic head may be unimportant in the 
early history of an oil field, but at a later period, after the gas pressure 
has diminished and a considerable portion of the oil has been removed, 
the oil sands constitute a convenient reservoir, and such water on 
entering them is capable of doing considerable damage. 

The factors causing artesian flows are well known and need not be 
discussed here, but some of the causes of unusually low hydrostatic 
head, leading to the conditions described above, may be mentioned. 
If the sand is a sealed lens completely filled with water it can neither 
receive nor yield water when it is penetrated by the drill. If, on the 
other hand, it is open at both ends so that there is free circulation 
the head may be either moderate or low, depending chiefly on the 
inclination or dip of the bed and the amount of resistance encoun¬ 
tered by the water in its passage between the sand grains (fig. 1, B). 
If the resistance is extremely low the head will be very low, for the 
water will follow the path of least resistance. In many wells of this 
kind the head is probably less than that of the water in the drill hole, 
and as circulation is comparatively free, part of this water will be 
absorbed. 

However, in some drill holes, in which the drilling water has dis¬ 
appeared into a sand with great rapidity, the conditions just described 


16 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

do not offer adequate explanation. For these drill holes, figure 1, D, 
which shows a water-filled sand lens with free outlet at the lower end 
but sealed at the upper, is suggestive. Under these conditions a 
negative head or partial vacuum would be created, and if such a 
sand were penetrated by the drill the drilling water might be taken 
up as fast as it could be poured into the well. These conditions do 
not depend on the complete sealing of the upper end of the lens, for 
the same principle w^ould operate to a lesser degree providing only 
that the outlet is larger and accommodates more water than the 
intake. As the freedom of circulation normally decreases with 
depth, the outlet might have to be considerably greater than the 
intake, but this relation is probably no less common than the reverse, 
by which a high positive head would be developed. 

It may be mentioned in passing that many geologists believe that 
meteoric and connate waters are confined to a relatively shallow zone 
near the earth’s surface, below which the rocks are normally dry. 
The literature of ore deposits contains many references to this belief 1 
and strong evidence in favor of it is also found in the Appalachian 
oil fields. In the fields of San Joaquin Valley, however, large amounts 
of water have been found at the greatest depths reached, more than 
4,000 feet, in the fields of the west side, and 5,000 feet in the Kern 
River field. 

- v / 

RELATION TO THE OIL. 

The lenticular rocks overlying the oil in the San Joaquin Valley 
fields include a number of well-recognized water sands. These sands 
may be traced within small areas, though wide correlations are impos¬ 
sible. Numerous factors influence the distribution of the water and 
the course of its circulation and therefore where irregular and len¬ 
ticular rocks are concerned it is impossible to predict in advance of 
drilling where the greatest flows will be found. 

The ground-water level, or the plane below wdiich most of the strata 
are saturated, varies from place to place but is generally within 300 
feet of the surface. Between this level and the horizon of the oil 
from one to a dozen or more water sands are found, the number 
depending on the locality and on the depth of the oil. In some local¬ 
ities no flows are encountered in the 300 feet or more of strata directly 
above the oil, but in others there is a water sand less than 50 feet 
above it. Sands yielding large quantities of water are generally 
encountered below the oil, the distance depending somewhat on the 
thickness and character of the oil zone itself. Where the oil is con¬ 
fined to sands in one zone 300 feet or more thick, there is generally a 
water sand between 10 and 100 feet below the base of the oil zone. 


1 One of the earliest papers is that of Kemp, J. F., The r61e of the igneous rocks in the formation of 
veins: Am. Inst. Min. Eng. Trans., vol. 31, pp. 1G9-198, 1902. 



OCCURRENCE OF WATER IN OIL FIELDS. 


17 


Where the oil occurs in several more widely separated sands water is 
usually encountered between them. 


In addition to the sands that are wholly filled with either oil or 
water there are sands that contain both, the oil occupying the up- 
slope and the water the down-slope portion. The topmost sand in 
the oil zone in the Westside Coalinga field, for example, contains 
water down the dip, and analogous conditions exist in several lo¬ 
calities in the Midway and Sunset fields. It is generally recognized 
that if any persistent oil sand in any of the fields could be followed 
far enough down the dip the oil would finally be found to be re¬ 
placed by water. 


The terms locally applied to waters in the three positions described 
arc respectively “top water,” “bottom water,” and “edge water.” 
It is natural for the driller, who is interested jirimarily in the position 
of the oil itself, to classify waters according to their position with 
regard to the oil, but his terminology is often ambiguous. The bot¬ 
tom water of an upper oil sand may be the top water of a lower, and 
edge water may be either top water or bottom water or both. These 
terms are perhaps too commonly used and too convenient to discard, 
but the term top water should be restricted to water above the highest 
oil sand, and the other terms should be used only when their meaning 
is perfectly clear. The terminology suggested by the writer (see p. 51), 
which is also based ultimately on the position of the water in relation 
to the oil, is believed to offer a basis for more rational distinctions. 


PHYSICAL CHARACTERISTICS. 

HEAD OR PRESSURE. 

In several fields of the San Joaquin Valley the water in many sands 
is under great pressure, and it has been necessary to devise special 
methods of shutting off this water in order to prevent its enter¬ 
ing the oil sands. In the McKittrick field, for example, several 
wells near McKittrick encountered water which is said to have 
flowed for a while over the derrick, and in the Midway-Sunset field 
many flowing waters have been struck at different depths, the 
greatest more than 3,500 feet. As a general rule, to which there 
are many exceptions, the pressure increases with the depth, and the 
waters below the oil zone are generally confined under considerable 
pressure. The head in most of the sands reported as water sands by 
drillers is more than 200 feet, and it has already been pointed out that 
many sands reported as dry probably carry water under a head of 
more than 50 feet. 

The pressure of the water in most sands, however, is not constant, 
but diminishes noticeably a short time after the sand is tapped. 
Waters that flow for months or years finally cease to flow, and the 
60439°—Bull. 653—17-2 



18 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

head of waters that rise hut do not reach the surface is also known to 
decrease. The rate of decrease in any given sand depends on local 
factors and may differ widely among neighboring wells, but the gen¬ 
eral decrease in any area as a whole is striking. 

In water wells outside of oil fields the pressure is generally either 
hydrostatic or artesian in character, or is due to rock pressure. 
Hydrostatic pressure is caused by the weight of the downward-bearing 
column of water, and its amount at any point is controlled chiefly by 
the difference in elevation of that point and the point at which the 
water enters the bed, and in practice by the fineness of the material 
through which the pressure is transmitted. The factors controlling 
hydrostatic head are fairly well understood and may be determined 
with considerable accuracy. Rock pressure is commonly believed 
to be the weight of the overlying column of rock, which exerts a com¬ 
pressive effect on the beds beneath it. During the deposition of the 
sediments this undoubtedly leads to closer packing of the grains, but 
after a state of equilibrium has been reached the effect of further 
compression is a matter of speculation, unless the rocks concerned 
are deeply buried. A factor often overlooked in this connection is 
the tensile strength of the overlying rocks, which may conceivably 
be great enough to relieve a part of the pressure from a given point. 
As the weight of the strata is thus somewhat irregularly distributed, 
the rock pressure on a body of ground water must be irregular. 
Rock pressure is doubtless an important factor under some conditions, 
but its effect is generally an unknown quantity. 

Gas pressure must also be taken into account in regions in which 
gas is contained in the rocks. In general the gas pressure in any 
sand is less than the weight of an overlying column of water, but 
there are many sands in which it is considerably greater and in 
which, therefore, its influence must be considered. If a sealed sand 
lens is filled partly with water and partly with gas under pressure, 
the water may flow out under great apparent head when the sand is 
tapped. (See fig. 1, E.) When the gas has expanded somewhat, the 
apparent head of the water decreases, and some, though not all, of 
the decrease in the head of oil-field waters is doubtless due to dimin¬ 
ishing gas pressure. Some puzzling differences in the head of these 
waters may also be ascribed to gas pressure, the effect of which can 
not be overlooked, although its ultimate cause has never been satis¬ 
factorily determined. 

Aside from the pressure exerted by a body of gas, the influence of 
gas liberated from solution in causing water to flow is also important. 
Hydrocarbon gas is dissolved in some waters, and many others con¬ 
tain carbon dioxide and hydrogen sulphide. These are partly lib¬ 
erated at the foot of the well, and act somewhat like an air lift in 
causing the water to flow. Their action is feeble as compared with 


OCCURRENCE OF WATER IN OIL FIELDS. 19 

the propulsive effect of a body of compressed gas, but it is doubtless 
more widespread and causes some waters to flow that might not 
otherwise quite reach the surface. 

In the oil fields of the west side of the valley much of the water is 
under high initial head or pressure, but hi the main Kern River field 
on the east side of the valley the pressure is notably lower. Its pres¬ 
ent pressures are not comparable with those in the more recently 
developed fields of the west side, but even in the early period of its 
development fewer flowing waters were found. Most of the impor¬ 
tant factors influencing head or pressure have probably entered into 
this difference; the geologic structure in the Kern River field is more 
gentle, and the sands are thicker and more persistent, the under¬ 
ground circulation is freer, and the initial gas pressures were con¬ 
siderably lower. 

TEMPERATURE. 

The temperature of the oil-field waters generally increases with 
depth at about the rate that is normal in most regions, or possibly at 
a slightly higher rate. The temperature of the shallow waters is gen¬ 
erally between 80° and 90° F., and that of the waters near the oil 
sands between 95° and 110° F. The waters from depths of 3,000 to 
4,000 feet in several wells have a temperature of 120° to 130° F., 
though that from similar depths in other wells is cooler. The geo¬ 
thermic gradient is fairly regular, so that the source of the water is indi¬ 
cated in a general way by its temperature, and a sand receiving much 
surface drainage is generally abnormally cool. The temperatures of 
some of the waters discussed in this report are given in the tables of 
analyses on pages 63, 66, 70, 73, 74, 76, and 77. The cooling effect of 
expanding gas, as well as several minor factors, may injure the value 
of temperature measurements made at the mouth of a well, so that 
some variation would be expected, and in addition it seems certain 
that the waters undergo chemical changes, probably exothermic in 
character, which may locally disturb the normal gradient still more. 

Measurements of the geothermic gradient have been made in sev¬ 
eral localities in North America and Europe, and it is interesting to 
note that Koenigsberger and Miihlberg 1 after studying and correcting 
these measurements conclude that the gradient is abnormally high 
in oil fields, and that temperature measurements may therefore be 
used in prospecting for oil. Their conclusions have not been gen¬ 
erally accepted, owing to the facts that the data available are deemed 
inadequate and that there are apparent exceptions. Although the 
average of the gradients measured by Koenigsberger and Miihlberg 
in oil fields is slightly higher than that of gradients in other regions, 


• Koenigsberger, Joh., and Miihlberg, Max, On the measurements of the increase of temperature in bore 
holes: Inst. Min. Eng. (England) Trans., vol. 39, pp. 617-644,1910; also liber Messungen der geothermischen 
Tiefenstufe: Neues Jahrb., Beilage Band 31, pp. 107-157, 1911. 




20 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

the wide variation between individual gradients in oil fields suggests 
that more data might reverse their results. Irregular variations, as 
stated above, also characterize the temperatures of the waters in the 
oil fields of the San Joaquin Valley. 

« 

GEOLOGIC CONDITIONS THAT INFLUENCE THE COMPOSITION OF 

WATER. 

GENERAL FEATURES. 

Owing to the fact that underground waters in a region of sedimen¬ 
tary rocks tend to follow the bedding jdanes, the structure or attitude 
of the rocks has an important effect on the freedom of the circulation, 
which in turn influences the chemical character of the waters them¬ 
selves. If salt water, for example, is present in the strata before 
they are folded some of it may be trapped in structural troughs or 
basins and held there indefinitely. Whether the water so trapped was 
originally salt or fresh, it is evident that during its long period of 
association with the rocks it will dissolve certain of their constituents 
and become more highly mineralized. The waters of the oil fields 
of the valley differ widely from one another in both their content of 
chloride and their total load of dissolved mineral matter, and it is 
thought that these variations are caused by such physical factors as 
the geologic structure, the lenticularity of the beds, and the amount of 
rainfall. The solution of rock constituents by underground waters 
is a somewhat complicated problem that may best be discussed in 
connection with the chemistry of the waters, but the distribution of 
chloride is so largely a physical problem that it will be considered here. 

ORIGIN OF SALT WATER IN ROCKS. 

When sediment is deposited on the floor of the sea it is saturated 
with sea water, which remains in the pores until it is elevated to 
form land. The compacting of the material necessarily forces out a 
large quantity of this water, but that remaining ordinarily fills the 
pore spaces of the rocks after they have assumed their normal bulk. 
Uplift, however, causes circulation of the water to commence, and 
meteoric water falling on the newly elevated land surface enters the 
beds and tends to dilute and force out the connate water—the sea 
water entrapped in the sediments. This replacement takes place 
with considerable rapidity under some conditions, but under others 
the connate water, only slightly altered by its contact with the rocks, 
may remain trapped for long periods of time. The freedom of the 
outlet by which the salt water may escape is the chief factor, for water 
trapped in a lens of sand entirely inclosed by shale might remain there 
indefinitely. Similarly, as circulation follows bedding planes, if the 
strata are folded into a closed basin or trough the water will accu- 


OCCURRENCE OF WATER IN OIL FIELDS. 


21 


Ululate m its deepest portion and remain there, somewhat as the 
surface waters of Great Salt Lake are held in their basin. Where 
the outlet is not entirely closed but is merely restricted, other factors 
enter into the problem, such as the volume and the head of the 
meteoric waters that are tending to drive out the connate water, 
the porosity of the materials through which the waters must pass, 
and such subordinate factors as the dip of the rocks and the distance 
from their outcrop. Even where all the conditions are favorable 
to the retention of the salt water it is evident that some of it near the 
surface will be leached out and that, other things being equal, the 
largest proportion will be retained at the greatest depths. The deeper 
of two deep wells in the same locality would ordinarily be expected 
to yield a more salty water, owing to the smaller volume of circula¬ 
tion in the deeper rocks as compared with those nearer the surface. 
In a region of lenticular beds irregularities are to be expected, for 
the freedom of circulation differs from bed to bed and some sands 
will therefore retain their salt water much longer than others. 

After marine sediments have been elevated to form land and the 
underground circulation thus set up has leached out part or all of the 
connate water the rocks may again subside beneath sea level. In this 
event the fresh water contained in the beds will be partly replaced by 
sea water, and sediments that are laid down over these beds will be 
saturated with sea water. After the second period of elevation has 
occurred and circulation has again been established the process of 
freshening will be repeated. Under these conditions it is evident 
that the older or deeper formations, having undergone longer con¬ 
tinued leaching, may contain less salt water than those nearer the 
surface, where the replacement by fresh water may be incomplete. 
Examples of salt water underlain by fresh water are not uncommon 
on the Atlantic Coastal Plain, 1 and it is possible that similar conditions 
exist in several places along the borders of San Joaquin Valley. 

In the foregoing paragraphs the burial and retention of sea water 
only has been considered, but it is evident that strata laid down in a 
fresh-water lake may contain entrapped fresh water, which is just as 
truly connate as entrapped salt water. In other words, the term con¬ 
nate water as originally employed 2 means simply water occluded in 
the sediments when they were deposited and is not restricted to any 
particular chemical type of water. On the other hand, if used in 
this strict sense, the term should be restricted to water laid down 
with the formation in which it is now found; it therefore should not 
be applied to water that has migrated from one formation to another, 

1 Sanford, Samuel, Saline artesian waters of the Atlantic Coastal Plain: U. S. Geol. Survey Water- Supply 
Paper 258, pp. 75-86,1911. 

Stephenson, L. W., and Palmer, Chase, A deep well at Charleston, S. C.: U. S. Geol. Survey Prof. Paper 
90, pp. 69-94, 1915. 

2 Lane, A. C., Mine waters and their field assay: Geol. Soc. America Bull., vol. 19, p. 501,1909. 





22 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

or to water that has entered the rocks during a second period of 
immersion. 

The general concept of connate water is a valuable one, but the 
practical application of the term in its strict sense is attended by so 
many difficulties that it seems advisable to redefine it in conformity 
to current usage. A sample of salt water may reasonably be called 
connate if it approximates ocean water in chemical composition and if 
it occurs in rocks of marine origin in which the circulation of the water 
is very slight. The water in beds of fresh-water origin may be thought 
to be connate, but as the composition of the body of fresh water in 
which the beds were deposited is unknown, the application of the term 
can not be supported by chemical evidence and must rest wholly on 
geologic considerations of a more or less conjectural nature. In actual 
practice, the term can not be applied to a specific sample of water 
unless chemical evidence can be adduced, that is, unless the composi¬ 
tion of the original body of water is available for comparison, and 
usually this is possible only when the water is of marine origin. Prac¬ 
tically, therefore, the term connate must be restricted to connate 
waters of the marine type, and so far as the writer can learn this 
accords with the common use of the term at the present time. On the 
other hand, it is generally impossible to ascertain how far a water has 
migrated or whether it is actually connate to the rocks in which it 
is now found. (See discussion of analysis 25, p. 61.) If it has 
migrated from one formation to another or if it entered the rocks 
during a later period of immersion, it is not strictly connate, but 
neither is it pluvial or meteoric. If it were ordinarily possible to 
determine these facts it might be advisable to introduce a new term, 
but as it is not the writer believes that the term connate may be 
extended to include such extraneous waters. Although Lane, 1 in 
introducing the term connate, notes that connate water may be either 
salt or fresh, neither he nor any other investigator, so far as the 
writer knows, has ever attempted to apply the term to specific samples 
of fresh water. If, however, this application should become desirable 
a qualifying adjective may be used to distinguish connate fresh water 
from connate marine water. Similarly, if it is desired to use the term 
in its strict etymologic sense—as water that was buried with the bed 
at the time of deposition—a phrase such as “ connate to the bed in 
which it is found” may be used. For practical purposes, therefore, 
connate water may be defined simply as fossil sea water. The term is 
so used in this report, and although it is recognized that connate fresh 
waters are thereby included with the meteoric or pluvial types there 
seems to be no practicable way of distinguishing them. 

The definition here adopted is thus based principally on chemical 
rather than geologic evidence, though as water in contact with rock 


1 Lane, A. C., op. cit. 





OCCURRENCE OF WATER IN OIL FIELDS. 


23 


tends to change in character it can not be expected that fossil sea 
water will long retain exactly its original composition. Water 
entrapped in the older rocks, like the Paleozoic, may have changed so 
materially that its origin, so far as chemical evidence goes, may be in 
doubt, but some of the salt water in the rocks of San Joaquin Valley is 
so similar to sea water that there can be little doubt that it is fossil sea 
water. (See Table 8, p. 73.) This view is strengthened by the fact 
that the differences in composition between it and normal sea water 
may be adequately explained by fairly definite chemical reactions and 
is corroborated by the fact that geologic conditions in the areas in 
which it occurs are such as to prevent free circulation, which explains 
why it has not been leached out. Some geologists hold that connate 
water can not be retained long in rocks that have been elevated above 
sea level and that salt ground waters are due to the leaching of salt 
deposits. However, waters that have leached salt deposits would 
ordinarily differ in composition from ocean water in several respects 
and would probably be unlike any waters in the San Joaquin Valley 
oil fields that are known to the writer. Moreover, as geologic condi¬ 
tions in that region seem to be locally favorable to the retention of 
connate water, the view ascribing salt waters to the leaching of hypo¬ 
thetic saline deposits nee^d not be considered further. 

\ 

RELATION OF GEOLOGIC STRUCTURE TO DISTRIBUTION OF SALT WATER 

IN THE OIL FIELDS. 

Though much of the deeper water in the oil fields of San Joaquin 
Valley is very salty, in some localities it is practically fresh. This dif¬ 
ference is believed to be due largely to difference in structural condi¬ 
tions. All the fields of the west side are characterized by similar 
structure, being associated with the minor anticlines that border the 
edge of Temblor and Diablo ranges. The anticlines and the synclines 
behind them in all these fields have a general southward plunge. In 
considering hydrologic conditions each field may be regarded as occu¬ 
pying one or more of the following positions: The eastern flank of the 
anticline near its north end, where erosion has uncovered and trun¬ 
cated the oil-bearing strata; the summit and flanks of the anticline, 
where the oil-bearing rocks are deeply buried and do not outcrop; 
the trough between the anticline and the main slope of the valley; 
and the western limb of this trough near the outcrop of the oil-bearing 
beds. If San Joaquin Valley itself be thought of as a great open 
trough with these structural features perched high on its western rim 
it becomes evident that the synclines constitute traps in which the 
ground water may be effectually ponded. In the first position men¬ 
tioned, however, drainage down into the main valley should be 
relatively free, and in the second and fourth positions the freedom of 
drainage would depend on the completeness with which the waters are 


24 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

ponded in the trough. It is perhaps noteworthy that the accumula¬ 
tion of oil in the first position seems to be unusual and is illustrated 
only in the northern part of the Eastside Coalinga field. 

These ideas seem to be supported by the character of the water 
in the four structural provinces distinguished. So far as data are 
available, all the synclines are characterized by more or less salty 
water, and the proportion of chloride at any point in the trough is 
apparently governed by its depth and distance from the outcrop. 

, The water near the axis of the Midway syncline, for example, is very 
salty, whereas, nearer the outcrop to the west, where fresh water 
may enter the beds, it is much less so, and every gradation between 
the two extremes may apparently be’ found. (See figs. 6 and 7 and 
discussion, pp. 86-91.) On the other hand, in the northern part of the 
Eastside Coalinga field, which is on the eastern slope of the southward- 
pitching anticline, the waters contain only a small proportion of 
chloride, many of them far less than is perceptible to the taste. (See 
analyses 35 and 36, Table 6, p. 69.) The pitch of the anticline has 
caused the oil-bearing strata in this locality to outcrop a short dis¬ 
tance west of the field, and as there is apparently no structural bar¬ 
rier to the east to prevent circulation down into the main valley, 
practically all the connate water has been driven from the beds. 
The removal of chloride has been even more complete north of the 
limits of the productive field, where the structure becomes truly 
monoclinal and the dip somewhat steeper. Chloride is much more 
abundant toward the southern end of the field, however, or down the 
pitch of the fold where the strata are deeply buried. 

A similar contrast is apparent if the Kern River field on the east 
side of the San Joaquin Valley is compared with the Midway field. 
The structure in the Kern River field is very much more gentle than 
that typical of the fields of the west side, and apparently no struc¬ 
tural barrier exists to pond the water. Furthermore, owing to the 
much greater abundance of water on the east side of the valley, the 
chlorides have been in large part removed, and such other salts as 
are derived from the rocks usually form only a dilute solution. The 
writer knows of only two waters whose analyses show a concentra¬ 
tion greater than 2,000 parts per million, and most of the waters 
contain less than 1,000 parts of dissolved mineral matter. (See p. 85.) 

The period of subsidence during which the salt water now present 
in the oil fields became entrapped in the rocks can not be determined. 
The Cretaceous and older Tertiary deposits were laid down beneath 
the sea and were once saturated with salt water, and some of the 
later Tertiary formations are also to a large extent of marine origin. 
However, much of the water originally entrapped in the Cretaceous 
sediments was probably leached out during later periods of eleva¬ 
tion, and some of the salt water now found in theso rocks doubtless 


OCCURRENCE OF WATER IN OIL FIELDS. 


25 


entered them during 


the Tertiary 


periods of subsidence. 


Further¬ 


more, the stresses incident to the folding of the strata may have 
caused migration from one formation to another; this appears to be 
the most plausible explanation for the local occurrence of salt water 
in the fresh-water beds of late Tertiary age. (See p. 61.) In one 
locality or another salt water is now found in all the Cretaceous and 
older Tertiary formations and in most of the later Tertiary deposits 
as well, but there is usually no way of telling whether or not it is 
connate to the beds in which it occurs, and doubtless much of it was 
entrapped during the most recent periods of immersion. 


GENERAL ASSOCIATION OF SALT WATER AND PETROLEUM. 

It has long been known that in most oil fields petroleum is rather 
closely associated with salt water, and many attempts have been 
made to explain this widespread association. Few analyses of oil¬ 
field waters have been made, however, and the presence of salt in 
many waters has probably been detected by the taste. Although 
presumably the water in most oil fields is salty, and in some is ex¬ 
tremely salty, it may be borne in mind that the degree of saltiness 
is known to be variable and must therefore be influenced to some 
extent by local conditions. 

Presumably on the assumption that all oil-field waters are strongly 
salty Ochsenius, 1 Zaloziecki, 2 Beeby Thompson, 3 and others have 
suggested that the chloride was concerned in the formation of the oil 
itself/ either by acting chemically on the organic matter or by 
retarding premature decomposition. Although there is as yet little 
chemical evidence to support these views it is possible that the 
chloride has exercised some such effect, or has influenced the polymeri¬ 
zation of the oil during a later period in its history. The fact that 
the present distribution of chloride in the oil fields of San Joaquin 
Valley is apparently controlled by local structural conditions would 
not necessarily refute this theory. Such influence as the salt water 
might have would be exercised during the earlier stages of formation 
of the petroleum; and as the diatomaceous shales which are the 
probable source of the California oil are known to have been laid 
down beneath the sea they must have been originally saturated with 
sea water. 

On the other hand, there is a possibility that the occurrence of salt 
water in oil fields may be everywhere explained by the simple prin¬ 
ciples that seem to be effective in the San Joaquin Valley fields, 
namely, that the water is more or less completely trapped in closed 

1 Ochsenius, C., Zur Entstehung des Erdoles: Chem. Zeitung, Band 15, pp. 935 and 1735, 1891; ErdOl- 
bildung: Deutsche geol. Gesell. Zeitschr., Band 48, pp. 239,685, 1896; Erd61 und Salz: Chem. Zeitung,Band 
21, p. 57, 1897. 

2 Zaloziecki, R., Zur Entstehung des Erdoles: Chem. Zeitung, Band 15, p. 1203, 1891. 

3 Thompson, A. B., Petroleum mining, p. 113, 1910. 



26 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY , CAL. 

sand lenses or by structural barriers. The very fact that the oil 
itself can accumulate and remain within a small area under high 
pressure for long periods of time implies that the underground 
circulation is decidedly restricted. Hence if salt water originally 
saturated the beds it is reasonable to expect that under most condi¬ 
tions some of it would be retained also. No very positive proofs of 
this simple explanation can be offered until more is known of the 
chemical character of oil-field waters in relation to physical condi¬ 
tions, but in the absence of evidence to substantiate the theory that 
chlorides are concerned in the formation of the oil, this suggestion 
may be worthy of consideration. 

Another view that may be mentioned in passing is that salt water 
in oil fields has certain peculiarities of composition which indicate 
that it is, in part at least, of deep-seated origin. 1 It has been shown 
that the distribution of salt water in the San Joaquin Valley oil 
fields may be explained on simple physical principles, and it will be 
shown below that this water has nearly the composition of sea water 
with certain modifications due to definite chemical reactions. There 
is nothing to show that it has emanated from the interior of the earth, 
and an appeal to recondite agencies is unnecessary. 

DISTRIBUTION OF WATER IN THE OIL FIELDS. 

The following notes on the occurrence of water in the several oil 
fields are included in order to enable one unfamiliar with the fields to 
understand more clearly certain features of the chemical relations of 
the waters. No attempt is made to describe local conditions in 
detail or the damage wrought by the intrusion of water into the oil 
sand. Most of the analyses on which this paper is based represent 
waters from the Coalinga, Midway, and Sunset fields, and reference 
to the physical conditions in these fields will again be made in dis¬ 
cussing the chemical relations of the waters. 

COALINGA FIELD. 

The Coalinga oil field is divided into two fairly distinct districts, 
the Westside and the Eastside fields. The Westside field is situated 
on the western limb of a syncline and the Eastside field is practically 
confined to the summit and eastern limb of the anticline to the east. 
The deeper portion of the syncline has not been explored. The 
ground-water level in the whole area is generally within 200 feet of 
the surface, and most of the water needed for industrial use is 
obtained from comparatively shallow water wells. Throughout the 
area the shallower waters are highly mineralized and are notable for 
their very high proportion of sulphate. 


1 Washbume, C. W., Chlorides in oil-field waters: Am. Inst. Min. Eng. Trans., vol. 48, pp. 687-094, 1915. 





DISTRIBUTION 'OF WATER IN OIL FIELDS. 


27 


In the Westside held many of the waters above the od sands are 
under considerable head, and water flowed at the surface from some 
wells for several years. Some of these top waters are very corrosive 
and have caused considerable damage by attacking and destroying 
the casing used to prevent their entrance into the oil sands. Strong 
water sands are generally encountered near the tar sand zone, and 
many of these waters contain hydrogen sulphide and are known as 
sulphur waters. In the deeper or eastern part of the Westside field 
there is a water sand a short distance above the oil zone but farther 
up the rise to the west this same sand carries oil. In most localities 
a similar condition apparently exists in a sand near the base of the 
oil zone; to the east this sand carries the “bottom water /’ but up 
the rise it is oil bearing and the first water below the oil is in the 
upper part of the Oligocene (?) shale. In general the water below 
the oil zone is confined under considerable pressure, and even now 
rises within a few hundred feet of the surface. 

Owing to the southerly pitch of the anticline on which the Eastside 
field is situated the strata outcrop a short distance west of the north¬ 
ern end of the field but at the southern end are deeply buried. As the 
beds dip rather steeply to the east in the northern part of the field, 
and as there is apparently no structural barrier to the east to restrict 
circulation, a relatively free passage is afforded such water as seeps 
in at the outcrop. In most sands the water is therefore not under 
very high head. It is not so highly mineralized as in the Westside 
field and is characterized by a low proportion of chloride. However, 
toward the southern end of the Eastside field the circulation is more 
restricted, and the average head is therefore higher and the percent¬ 
age of dissolved matter, especially chloride, is greater. The occur¬ 
rence and distribution of the water in the Eastside field is not yet 
thoroughly understood and presents many puzzling irregularities. 

LOST HILLS FIELD. 

The Lost Hills field extends in a narrow belt along the axis of a 
* well-defined anticline, the continuation of that which dominates the 
structure in the Coalinga field. Most of the strata penetrated by the 
wells probably do not outcrop, and conditions are therefore not favor¬ 
able for free circulation. On the west or inclosed slope of the anti¬ 
cline very salty water is obtained at relatively shallow depths, in 
some places within a few hundred feet of the surface, but farther east 
the shallow water contains a high proportion of sulphates. From the 
scanty information available it appears that the water near the oil 
zone is very salty and is confined under considerable pressure. 

McKTTTRICK FIELD. 

The McKittrick field is characterized by more complex structural 
features than any other field in San Joaquin Valley. In a general 


28 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

way, tho productive district lies on the Hanks of three folds, but the 
structure is complicated by overturned folds and thrust faults. 

The circulation of the shallower waters is apparently controlled 
chiefly by the topography, these waters being more abundant and 
more highly mineralized in the McKittrick Valley than in the foot¬ 
hills to the west. The deeper circulation, however, is undoubtedly 
affected by the complex geologic structure, and little can be said of 
its course or nature until more complete information is available. 
The oil-bearing zone is generally underlain by a sand carrying warm 
water under considerable pressure. In part of the field the oil sands 
have been flooded, and it is generally believed that the damage had 
been done by this water. Whatever its original source, the water 
that has flooded the oil zone is very uniform in chemical composition 
and is probably the yield of a single water sand. Little variation is 
shown by about 30 analyses of this water at the writer’s disposal, 
and analysis 89 (Table 14, p. 85) is entirely representative. 

MIDWAY-SUNSET FIELD. 

The Midway and Sunset fields are arbitrary divisions of a great oil- 
producing area, and as the geology of both fields is similar they may 
best be described together. The developed area extends west from 
the east slope of the Buena Vista anticline across the Midway syn¬ 
cline and up on its western limb, where the oil-bearing strata outcrop. 
The western limb of the trough is not a regular slope as in the West- 
side CoaJinga field but is broken by several minor anticlines, all pitch¬ 
ing to the southeast. 

The ground-water level in the Midway-Sunset field is lower than 
in the Coalinga field and is generally 250 to 500 feet below the sur¬ 
face. Along the hilly western part of the field the shallower water 
is almost lacking and in some localities is not abundant even to the 
depth of the oil zone. Generally, however, some water is found near 
the tar sands and also between them and the oil. At a variable depth 
below the oil zone, usually less than a hundred feet, abundant sup¬ 
plies of warm water under considerable pressure are found. Owing 
to the scarcity of shallow water this “bottom water” is widely used 
for industrial purposes in this part of the field. 

In the Midway Valley and the Buena Vista Hills, which are the 
surface reflections of a syncline and an anticline, respectively, the 
water conditions are somewhat different. In the valley moderate 
supplies of water may generally be obtained at a depth of 200 to 
500 feet, but in many localities even the shallower water contains 
a remarkably high percentage of sodium chloride. In the Buena 
Vista Hills the water level is generally lower, but the water is simi¬ 
larly salty. The percentage of salt increases with depth, but at a 
variable rate; in some localities water from 700 feet is almost fresh 


I 


OCCURRENCE OF WATER IN OIL FIELDS. 29 

enough to be potable, whereas in others it is nearly as salty as sea 
water. Many of the deeper top waters are confined under high 
pressure and flow at the surface. In most localities there is a rising 
or flowing water a short distance below the top oil sand, and in the 
deeper part of the syncline this oil sand is itself water bearing. 
Where second and third oil sands have been found, strong water 
sands are generally present between them. Although the water 
pressure as a rule is high, it is decidedly variable, and “dry” sands 
have been reported in many places. The deeper waters in this part 
of the field are fairly uniform in chemical character but differ from 
those at the same horizon in the shallower western part of the field. 
(See figs. 6, p. 88, and 7, p. 91.) Their average temperature is also 
different, being ordinarily some 10° higher. 

KERN RIVER FIELD. 

The Kern River field, lying on the lowest foothills of the Sierra 
Nevada on the east side of San Joaquin Valley, differs in many 
respects from those just described. The geologic structure is rela¬ 
tively simple; the strata lie in a gentle monocline, which is modified 
in places by minor wrinkles. The oil sands are very thick and are 
highly productive, but the gas pressure has never been very high. 

Kern River, which has a large drainage basin in the Sierra Nevada 
flows along the edge of the field. The waters draining from the Sierra 
are very different in chemical character from the waters on the west 
side of the valley and contain only a very small amount of dissolved 
salts, which are chiefly carbonates. The ground-water level in the 
Kern River field is high, and in most localities abundant supplies of 
potable water are obtained relatively close to the surface, and thence 
at short intervals down to a depth of many hundred feet. In general 
the percentage of dissolved salts increases with depth, but even in 
the deepest waters reached is usually less than in the average shal¬ 
low water in the fields of the west side. Owing to the sandy char¬ 
acter of the strata and to the fact that no pronounced structural 
barrier separates the field from the valley proper, the underground 
circulation is less restricted than in most of the fields of the west 
side, and the general water pressure is therefore comparatively low. 
Flowing waters have been encountered, but they are not common. 

ANALYSIS OF WATER AND INTERPRETATION OF 

RESULTS. 

MINERAL CONSTITUENTS IN WATER. 

Natural waters are essentially solutions of mineral substances 
which have been derived from the rocks or other material with which 
the waters have come in contact. All solutions may be regarded as 
homogeneous bodies, through which the mineral substances are 


30 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

uniformly distributed, and all solutions have definite properties, 
which depend on the nature and proportional amounts of the sub¬ 
stances of which they are composed. By chemical analysis of 
water only the proportional amounts of the constituents are deter¬ 
mined. The nature of each constituent, that is, its conduct toward 
other substances whose natures are known, has been learned by other 
methods, and as the properties of a solution are an assemblage of 
the properties of all its constituents, the properties of a water may 
be deduced from the statement of its analysis. 

The amount and character of the mineral substances dissolved in 
different waters vary greatly and depend on many factors. Chief 
among these are the chemical character and physical condition of 
the materials encountered, the heat and pressure, the duration of 
the contact, and the amount and character of the substances pre¬ 
viously dissolved. Water Under a given temperature and pressure 
can dissolve only a definite amount of any substance; and if the 
heat and pressure are lowered, as, for example, when an underground 
water emerges at the surface, the excess of dissolved matter may go 
out of solution as a precipitate. It is through this readjustment to 
changed conditions that mineral matter is deposited around some 
springs or wells. Similarly, if two waters carrying different salts 
in solution come into contact, a chemical reaction may take place 
and some of the dissolved material may be precipitated. Although 
many of the reactions that take place are obscure and can not be 
completely explained, the properties of natural solutions, which are 
the net results of these reactions, furnish a rational basis for general 
classification. 

In addition to dissolved mineral solids or gases, which chiefly deter¬ 
mine the chemical properties of a water, two other classes of sub¬ 
stances are generally present—material in suspension, which can be 
removed by filtering, and material in colloidal solution, a state inter¬ 
mediate between suspension and true solution. In the present 
study consideration has been given chiefly to the commoner dis¬ 
solved mineral substances. Small amounts of several elements, such 
as lithium, barium, phosphorus, and boron, are probably present in 
some of the oil-field waters, but they do not materially affect the 
quality of the water and their determination is not essential to a 
study of the relations of water to petroleum. 

COLLECTION OF SAMPLES. 

In most districts the collection of representative water samples for 
analysis is a simple matter, but in the oil fields, where the universal 
aim is to shut the water out of the wells, it is often very difficult. In 
wells that supply water for industrial uses the depth of the water 
sands is generally known, and samples can, of course, be easily taken, 


ANALYSIS OF WATER AND INTERPRETATION OF RESULTS. 31 

but the waters that can be obtained in this way are few. Some of 
the oil wells produce water which is known to come from a certain 
depth, but generally its exact source is unknown. In the oil fields, 
where sharp variations in the character of the water may occur within 
short vertical distances, too much care can not be exercised in the 
collection of samples. When a sufficient number of authentic samples 
of typical waters in any area has been collected and analyzed it will 
then be possible, by comparison with these standards, to form an 
estimate of the probable source of any water. 

Authentic samples can usually be taken only while drilling the 
well or while repairing it later. Flowing waters may, of course, be 
easily sampled, and the only precaution necessary is to let the water 
flow long enough before sampling to insure complete washing out of 
the drilling water from the hole. When the well is being drilled by 
the standard method the collection of samples is not especially diffi¬ 
cult, and samples uncontaminated by water from upper sands may 
generally be obtained after the drilling water has been bailed out. 
Under some conditions it is possible to obtain a fairly satisfactory 
sample merely by running the bailer to a point near that at which 
the water is entering the drill hole. When the circulating or rotary 
systems are used the proper collection of samples is often difficult 
or even impossible. Waters that flow when the pressure is released 
may be sampled at the expense of slight trouble, and if a string of 
casing is to be set within a short distance of a strong water sand, a 
sample of this water may be obtained while drilling is suspended. 
However, the rotary drill tends to mud up or plaster the walls of the 
hole and thus shut off flows of water, and if one of these flows breaks 
forth later the driller is likely to suppose that it comes from a deeper 
sand. 

In view of these uncertainties it is evident that unless the location 
of the water can be positively determined its analysis should not be 
used as a standard for exact comparison. For this reason it is the 
more desirable to collect samples carefully, and label them accurately, 
whenever good ones can be obtained, as when a flowing water is 
encountered. 

CHEMICAL ANALYSIS. 

DETERMINATION OF CONSTITUENTS 

The common mineral constituents of natural waters may be divided 
into two groups, those which have definite chemical relations with 
some other constituent and those which are probably present as col¬ 
loids. The colloid group comprises silica, iron oxide, and alumina. 
These substances, like those in the former group, may perhaps be held 
in solution in some waters, but ordinarily they are considered to be not 
in actual solution, and are conventionally reported as the oxides 
silica (Si0 2 ), ferric oxide (Fe 2 0 3 ), and alumina (A1 2 0 3 ). The con- 


32 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY , CAL. 

stituents of the other group are of two kinds, the positive radicles or 
bases, chiefly sodium, potassium, calcium, and magnesium, and the 
negative or acid radicles, chiefly sulphate, chloride, carbonate, and 
bicarbonate. The several constituents of each kind have different 
but definite capacities for reacting with or holding in solution or 
equilibrium constituents of the other kind. The two kinds of con¬ 
stituents in a water are always in chemical equilibrium; that is, the 
sum of the reaction capacities, or “ reacting values,” of the positive 
radicles is equal to the sum of the reacting values of the negative 
radicles. 

The number of constituents to be determined and the accuracy 
with which the work is done differs with the use to which the analysis 
is to be put, but in general the following determinations are desirable: 
Sodium (Na), potassium (K), calcium (Ca), magnesium (Mg), iron 
(Fe), aluminum (Al), sulphate radicle (S0 4 ), chloride radicle (Cl), 
nitrate radicle (N0 3 ), carbonate radicle (C0 3 ), bicarbonate radicle 
(HC0 3 ), silica (Si0 2 ), and total solids at 180° C. It is well also to 
test waters from oil fields for sulphide (S), a nonvolatile negative 
constituent, and the volatile substances hydrogen sulphide (H 2 S), and 
carbon dioxide (C0 2 ). The quantity of suspended matter and the 
quantity of organic matter also are usually determined. 

Iron and aluminum are usually precipitated and weighed together 
and reported as the oxides (Fe 2 0 3 -{-Al 2 0 3 ) in industrial analyses, and 
carbonate and bicarbonate are often not distinguished from each 
other. The laborious determination and separation of sodium (Na) 
and potassium (K) is omitted in many industrial analyses, and the 
content of these two substances together is calculated, after the acids 
and the other bases have been determined, by assuming the presence 
of sufficient sodium and potassium to complete the balance of reacting 
values between the bases and the acids. This implies, of course, that 
the determination of all the other radicles is absolutely correct, which 
is practically never the case; whatever errors are made in the deter¬ 
mination of all the other radicles are repeated and thrown together 
in the calculation of the alkalies. This practice thus conceals all 
error of analysis and makes it impossible to ascertain the accuracy 
of the analysis from the reported figures. If, on the other hand, all 
the radicles are actually determined the bases can be balanced against 
the acids and the discrepancy discovered. Even with reasonably 
careful work the unavoidable errors in determination usually amount 
to 1 per cent and may be 4 or 5 per cent. 

STATEMENT OF ANALYSIS. 

In analyzing a natural water the chemist can determine only the 
proportions of the mineral substances that it holds in solution. He 
can not determine what compounds have been dissolved, nor can he 


ANALYSIS OF WATER AND INTERPRETATION OF RESULTS. 33 

ascertain by the ordinary methods of analysis what compounds, if 
an y> oxist in the solution; his work is limited for the most part to 
the determination of the roots or portions of compounds that are 
known as radicles. In fact, present chemical knowledge indicates 
that a salt dissolved in water largely ceases to exist as an actual com¬ 
pound; according to the ionic theory it becomes partly dissociated 
into its component radicles, which become electrically charged or 
ionized, and it participates in chemical reactions only in so far as it 
is ionized. Even if it were held that the radicles of dissolved salts 
are actually combined it is a chemical and mathematical impossi¬ 
bility to ascertain by analysis to what extent a given base is combined 
with a given acid. 1 Despite this condition it is common practice to 
report hypothetical combinations by several methods of calculation, 
founded on different theories or devised from different points of view, 
in accordance with wliich the radicles are apportioned to one another. 
As a result of this difference of opinion it is impossible to compare the 
results of one chemist with those of another until the analytical data 
have been reduced to a statement of all the radicles actually deter¬ 
mined. It has been shown that the character of a water for industrial 
purposes, its fitness for domestic use, and its relation to its environ¬ 
ment can be defined without recourse to hypothetical combinations. 2 

As there appears to be no valid reason for reporting analyses in 
hypothetical combinations and as it is impossible to compare analyses 
so reported by different chemists, the analyses in this report have been 
calculated to ionic form in order to show the amounts of the radicles 
actually found by the analyst. They have also been calculated to 
parts per million, the proportion most suitable for comparison, in 
order to avoid confusion due to the use of different units, such as 
grams per United States gallon, percentage, and parts per hundred 
thousand. 

For the convenience of those who may desire to transform results 
into parts per million it may be stated that 1 grain per United States 
gallon is equivalent to 17.1 parts per million, 1 grain per imperial 
gallon to 14.3 parts per million, 1 part per hundred thousand to 10 
parts per million, 1 gram per kilogram to 1,000 parts per million by 
weight, and 1 gram per liter to 1,000 parts (weight) per million 
(volume). All the analyses in this report made by the Geological 
Survey are stated in parts by weight per million volume, and the 
remaining analyses are' believed to be also stated in this way. 

1 Dole, R. B., Hypothetical combinations in water analysis: Jour. Ind. and Eng. Chemistry, vol. 6, 
pp. 710-721, 1914. 

2 Stabler, Herman, The mineral analysis of water for industrial purposes and its interpretation by the 
engineer: Eng. News, vol. 60, p. 355, 1908; Some stream waters of the western United States, with chapters 
on sediment carried by the Rio Grande and the ind ustrial application of water analyses: U. S. Geol. Survey 
Water-Supply Paper 274, pp. 165-181,1911. Clarke, F. W., The data of geochemistry, 3d ed.: U. S. GeoL 
Survey Bull. 616, pp. 59-61,1916. See also U. S. Geol. Survey Water-Supply Paper 254, pp. 233-258,1910, 
and Water-Supply Paper 259, pp. 173-197, 1912. 

60439°—Bull. 653—17-3 




34 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


The factors in the accompanying table may be used for converting 
statements in hypothetic combinations into ionic form. The product 
obtained by multiplying the reported content of each salt by the 
appropriate factor is the content of the positive radicle or base, and 
the difference between this product and the reported content of the 
salt is the content of the negative or acid radicle in the compound. 
The aggregate for each radicle in the various salts is the total quantity 
of that radicle in the water. Silica, iron oxide, and alumina may 
generally be considered colloids and so retained in the restated 
analysis. 


Factors for calculating the amount of the base or 'positive radicle in various salts. 


Given— 

To find— 

Factor. 

Calcium sulphate (CaS0 4 ). 

* 

Calcium (Ca). 

0. 294 

Calcium chloride (CaCl 2 ). 

.do. 

.361 

Calcium carbonate (CaC0 3 ). 

.do. 

.400 

Calcium bicarbonate (CaH■>( 003 ) 2 ). 

.do. 

.247 

Magnesium sulphate (MgS0 4 )..!.. 

Magnesium (Mg).. 
.do. 

.202 

Magnesium chloride (MgCl 2 ) .. 

. 255 

Magnesium carbonate (MgCOp. 

.... do. 

.288 

Magnesium bicarbonate (MgH 2 (C 0 3 ) 2 ). 

.do. 

.165 

Sodium sulphate (Na 2 S 0 4 ) T........ 

Sodium (Na). 

.324 

Sodium chloride (NaCl). 

.do. 

.394 

Sodium carbonate (Na 9 C 0 3 ). 

.do. 

.434 

Sodium bicarbonate (NaHCOa). 

.do. 

.274 

Sodium sulphide (Na^S).. 

.do. 

.590 

Sodium acid sulphide tNaHS). 

_ do. 

. 411 

Potassium sulphate (K 2 SOP. 

Potassium (K).... 
.do. 

.449 

Potassium chloride (KC1). 

.524 

Potassium carbonate (K 2 CO 3 ). 

.do. 

.569 

Potassium bicarbonate (KHCO 3 ). 

.... do . 

391 

Hydrogen sulphide (H 2 S). 

Hydrogen (H).... 

.059 



For illustration the details of converting an analysis into ionic form 
in parts per million are given. The labor involved is considerably 
lessened if a slide rule or similar calculating machine is used. 


Grains per 

Analysis as reported : u. S. gallon. 

Calcium sulphate (CaS0 4 ). 3. 79 

Calcium carbonate (CaC0 3 ). 7. 90 

Sodium chloride (NaCl)... L .40. 60 

Sodium carbonate (Na 2 C0 3 ).21. 70 


73. 99 


Recalculation: 

3.79 grains CaS0 4 X .294. 1.11 Ca 

3.79 - 1.11. 2. 68 S0 4 

7.90 grains CaC0 3 X .400 . 3.16 Ca 

7.90 - 3.16 . 4. 74 C0 3 

40.60 grains NaCl X .394 . 16. 00 Na 

40.60 - 16.00 . 24. 60 Cl 

21.70grains Na 2 C0 3 X .434 . 9. 43 Na 

21.70 - 9.43 . 12. 27 C0 3 





























































ANALYSIS OF WATER AND INTERPRETATION OF RESULTS. 35 


Recalculation—Continued. 

Total Ca =1.11 +3.16 . 
Total Na =16.00+9.43 . 

Total S0 4 .. 

Total Cl. 

Total C0 3 =4.74 +12.27 


Grains per 
U. S. gallon. 

.... 4. 27 
.... 25.43 
.... 2.68 
.... 24.60 
.... 17.01 


73. 99 

Grains per Parts per 

U.S. gallon. million. 

Ca = 4. 27 X 17.1= 73.1 
Na =25. 43 X 17.1=435. 2 
S0 4 = 2. 68 X 17.1= 45. 9 
Cl =24.60 X 17.1=421.1 
C0 3 =17. 01 X 17.1=291.2 

73. 99 1,266. 5 

Proof: 73.99X17.1=1,266.5. 

REACTING VALUES. 

The statement of a water analysis in ionic form in parts per million 
shows numerically the relative proportions of the several radicles by 
physical weight, hi terms of gravity, and therefore is not a numerical 
representation of the water as a chemical reagent. A form of state¬ 
ment more convenient for study and comparison is that of reacting 
values, which shows numerically the relative proportions of the radi¬ 
cles by chemical weight, in terms of capacity for reaction. It is pos¬ 
sible to calculate either form of statement from the other, because for 
each radicle there is a fixed ratio between physical weight and capa¬ 
city for chemical reaction, though the ratios for the several radicles 
are different and the relation between the two forms of statement is 
therefore complex. The reacting value per unit weight of magnesium, 
for example, is much higher than that of sulphate, 10 parts of mag¬ 
nesium being chemically equivalent to 39.5 parts of sulphate. In 
order to understand the possibilities of reaction of the radicles in a 
water they should be considered as individuals acting together under 
the law of equivalent combining weights, each contributing its pro¬ 
portional share to the balance of the system. 

In order to translate an analysis from the ionic form into a form 
which expresses the chemical balance of the radicles, it is convenient 
to calculate the reacting values of the radicles. Stabler 1 has sug¬ 
gested that this be done by multiplying the weight of each radicle 
by its “ reaction coefficient/ ’ which he defines as the chemical react¬ 
ing power of a unit weight of the radicle. The reaction coefficient of 
a radicle is the ratio of the reaction capacity of one part of that 
radicle to the reaction capacity of eight parts of oxygen; in numerical 
value it is the valence of the radicle divided by its weight on the 

1 Stabler, Herman, The mineral analysis of water for industrial purposes and its interpretation by the 
engineer: Eng. News, vol. 60, p. 355, 1908: also chapter on the industrial application of water analyses in 
U. S. Geol. Survey Water-Supply Paper 274, pp. 165-181,1911. 












36 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


atomic scale. The following table shows the reaction coefficients of 
the positive and negative radicles most commonly found in waters: 

Reaction coefficients of positive and negative radicles most commonly found in waters. 


Positive radicles. 

Reaction coeffi¬ 
cients. 

Negative radicles. 

Reaction coeffi¬ 
cients. 

Rodinm fNa'l 

0.0434 

Sulphate (S0 4 ). 

0.0208 

Potassium fTO 

.0256 

Chloride (Cl). 

.0282 

Ca.lo.inm (Pa) 

.0499 

Nitrate (NO 3 ). 

.0161 

Masmesiiim 

* .0821 

Carbonate (CO 3 ). 

. 0333 

Hydrogen (H) . 

.992 

Bicarbonate (HCO 3 )... 

.0164 



Sulphide (S).j. 

.0622 


The reacting values of silica, iron, and alumina have been omitted 
from this table, as it is generally assumed that these substances are 
present as oxides in the colloidal state and therefore take no part in 
the chemical system of acids and bases. Stabler prefixes the letter r 
to the symbol of a radicle to designate its reacting value, and the 
same symbolization will be followed in this report. 

When the weights of the radicles have been translated into their 
reacting values the chemical nature of the whole system becomes 
apparent. Comparison is further facilitated, however, if the reacting 
values are reduced to a percentage basis, and this computation has 
been applied to all of the analyses here discussed. It will be observed 
that inasmuch as the sum of the positive radicles (bases) must be 
chemically equivalent to the sum of the negative radicles (acids), the 
reacting values of the two groups should be the same, each making 
up 50 per cent of the total. This principle is utilized by the chemist 
in making a partial analysis wherein the alkalies are calculated by 
difference. If the analysis under consideration is of this type the 
sum of the reacting values of the bases and acids should therefore be 
the same, but if all the constituents have been directly determined 
unavoidable errors usually cause the totals of basic and acidic reacting 
values to differ slightly and this difference is an index of the accuracy 
of the analysis. 

The conversion of the following analysis from the ionic form into 
reacting values is included in order to make this explanation clearer: 

Conversion of analysis from ionic form into reacting values. 

Parts per Reaction Reacting Reacting values 


million. coefficients. values, in per cent. 

Na. 435.2 X 0.0434 = 18.88 41.9 

Ca. 73.1 X • 0499 = 3.64 8.1 


508.3 22.52 50.0 

S0 4 . 45.9 X . 0208 = .95 2.1 

Cl. 421. 1 X . 0282 = 11. 87 26. 4 

C0 3 . 291.2 X , 0333 = 9.70 21.5 


758.2 22.52 50.0 








































ANALYSIS OF WATER AND INTERPRETATION OF RESULTS. 37 

As the figures representing the reacting values of the radicles have 
a greater chemical significance than those representing their weight, 
it is generally preferable to use the reacting values in comparing or 
studying analyses. Hence; statements in this report regarding the 
percentage of radicles present in waters refer to the percentage by 
reacting value, unless otherwise stated. 

PROPERTIES OF REACTION. 

Chase Palmer 1 has proposed a system for the classification and 
comparison of natural waters based on certain well-known properties 
of the solution as a whole, and his system is the one followed in this 
report. The writer has found this system very valuable, for it 
emphasizes certain differences between waters that are fundamental 
from the standpoint of the geologist and the industrial chemist, and 
is very convenient in the comparison of analyses. 

When different salts are dissolved in water they impart different 
qualities to the solution. A simple solution of sodium carbonate, for 
example, is soft and alkaline; one of sodium chloride is soft, but is 
neither alkaline nor acid, being neutral or saline, and one of calcium 
chloride is hard and saline. If the separate salt solutions are mixed, 
the resulting solution still has definite and determinable properties. 
For example, if 90 parts of sodium chloride and 10 parts of sodium 
carbonate are dissolved in water, the properties of the composite 
solution will be a summation of those of the solutions of the separate 
salts; in other words, the composite solution is characterized by 90 
per cent salinity and 10 per cent alkalinity. If to this solution cal¬ 
cium chloride is added, the percentage of these properties is altered, 
and a third property, hardness, is introduced. In a mixed solution 
of this kind it is no longer possible to state how much of each salt is 
present;, reactions have taken place and it is impossible to learn by 
analytical methods the order of the combinations that have resulted. 
Chemical analysis can determine only the amounts of the different 
radicles present. 

Although for the sake of simplicity the properties or qualities of 
the solution have in the preceding paragraph been ascribed to various 
salts, they are in reality due to the radicles themselves, uniformly 
distributed and held in balance; and inasmuch as the salts can not 
be determined they need not be considered further. • The general 
reactive properties of the solution may be readily deduced from the 
amounts of the radicles present, and in order to do this without 
undue complication those radicles which are similar chemically or 
associated geologically may conveniently be grouped together. Thus, 
the common bases may be grouped as alkalies (Na and K) and alka- 


i Palmer, Chase, Geochemical interpretation of water analyses: U. S. Geol. Survey Bull. 479, 1911. 





38 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

line earths (Ca and Mg), and the common acids as strong acids (Cl, 
S0 4 , and N0 3 ) and weak acids (C0 3 , HC0 3 , and S). The reactive 
properties of a water are governed by the respective proportions of 
these groups. Thus, if the value of the alkalies exceeds that of the 
strong acids, the hardness of the water may be removed simply by 
boiling, but if the strong acids exceed the alkalies, the water is per¬ 
manently hard. Similarly, if the value of the strong acids is less 
than that of the alkalies plus the earths, the water is characterized 
by alkalinity, but if it is greater the water is acid. 

In order to define more exactly the properties of a water, Palmer 
considers in detail the balances that may exist between the two basic 
and two acid groups of radicles and assigns to each a name. Salinity 
is defined as the property induced by the strong acids and alkalinity 
as that measured by the weak acids. The properties due to the 
presence of alkalies are called primary, and those due to the presence 
of the alkaline earths secondary properties. Hence the balance 
between the alkalies and the strong acids is called primary salinity 
and that between the alkaline earths and the weak acids secondary 
alkalinity, which is more commonly known as temporary hardness. 
If the strong acids exceed the alkalies, the excess must be held in 
equilibrium by the alkaline earths, and this balance is accordingly 
called secondary salinity, which is permanent hardness. If, on the 
other hand, the alkalies exceed the strong acids, the excess is bal¬ 
anced against the weak acids, and this balance is known as primary 
alkalinity. The two last-named properties are obviously incompati¬ 
ble ; nearly all waters are characterized by either one or the other, 
but a water can not exhibit both. All the oil-field waters are char¬ 
acterized by primary salinity and secondary alkalinity and by either 
primary alkalinity or secondary salinity. The three properties fur¬ 
nish a rational basis for classification and preliminary study, and are 
evidently far more convenient for general comparison than the de¬ 
tailed analyses. 

The manner in which these properties are deduced from the analysis 
is shown graphically in figure 2, which represents analysis 31 (Table 5, 
p. 66). It is assumed that the analysis has already been converted 
into the ionic form and that the reacting values of the radicles have 
been determined and reduced to a percentage basis as previously 
described. In this form the values of the basic radicles constitute 
50 per cent of the total and those of the acid radicles 50 per cent. 
In the figure the bases and acids have been plotted to scale in two 
columns of equal length, the alkalies and strong acids being placed 
at the bottom and the earths and weak acids above. In the central 
column are shown the properties of reaction that result from the 
proportions of these groups shown. As primary salinity is due 
to the balance between equal values of the alkalies and strong acids 


ANALYSIS OF WATER AND INTERPRETATION OF RESULTS. 39 


Properties oF 
reaction 

---A- 


Acids 


Bases 


its amount is determined by the smaller of its two components. In 
other words, the 22.3 per cent of strong acids present, in connection 
with an equal amount of alkalies, forms 44.6 per cent of primary 
salinity. This leaves an excess (19.5 per cent) of the alkalies which 
balances with an equal value of the weak acids and induces the prop¬ 
erty primary alkalinity to the extent of 39 per cent. Of the 27.7 
per cent of weak acids 8.2 per cent are then left 
in balance with the total (8.2 per cent) alkaline 
earths, which gives rise to 16.4 per cent of sec¬ 
ondary alkalinity. This water is therefore char¬ 
acterized by 44.6 per cent primary salinity, 39 
per cent primary alkalinity, and 16.4 per cent 
secondary alkalinity. On the basis of these prop¬ 
erties, or relations of reacting values, it may be 
rationally classified or compared with any other 
water. 

In the analysis selected the alkalies exceed the 
strong acids and therefore induce primary alka¬ 
linity. If the reverse were true, and the strong 
acids exceeded the alkalies, it is evident that a 
different property would result. In such a water 
some of the strong acids would be balanced by 
the alkaline earths and secondary salinity would 
result instead of primary alkalinity; in other 
words, the water would be permanently hard. 

The writer has found this distinction one of the 
most valuable features of Palmer’s classification, 
for by it all waters are separated into two impor¬ 
tant groups. The distinction is valuable indus¬ 
trially, for it separates permanently hard waters 
from those whose hardness is mostly lost on boil¬ 
ing. The distinction is of equal importance geo¬ 
logically. Thus, the surface waters on the west 
side of San Joaquin Valley are characterized by 
high sulphate and low carbonate and by roughly 
equal amounts of the alkalies and alkaline earths; 
some of the strong acids are balanced by alkaline 
earths and the waters have, therefore, the prop¬ 
erty of secondary salinity. On the other hand, in most of the waters 
associated with the oil the alkalies are very high and sulphate is 
lacking; in these waters some of the alkali group are in equilibrium 
with weak acids and the waters therefore have the property of pri¬ 
mary alkalinity. By a study of the properties of the waters all the 
stages in the transition from the extreme secondary saline type to the 
extreme primary alkaline type may be definitely traced, and distinc- 



Figure 2.—Graphic repre¬ 
sentation of analysis 31 
(Table 5, p. 66), showing 
method of deducing the 
properties of a water from 
its composition. 






























































40 OIL-FIELD WATERS IK SAN JOAQUIN VALLEY, CAL. 

tions become apparent that do not suggest themselves in a study of 
the original analysis. 

In addition to the three properties of reaction two other factors 
may be taken into account as criteria for comparison. One of these 
factors is the ratio of the chloride to the sulphate radicles, for in 
Palmer’s system these radicles are classed together as strong acids. 
Since the strong acids give rise to salinity, chloride salinity and 
sulphate salinity may be distinguished, and these may conveniently 
be expressed as percentages of the total salinity. For example, the 
sulphate salinity ratio in analysis 31 (shown graphically in fig. 2, 
p. 39) is rS0 4 divided by rS0 4 +rCl, or 13 divided by 22.3 = 58.3 per 
cent (of the total salinity). The other factor is the concentration of 
the solution, or the total amount of dissolved solids. In general, the 
concentration of oil-field waters of any one type is fairly constant, 
but it may vary widely and therefore should not be lost sight of. In 
gome waters it may also be desirable to determine the ratio of 
sulphate to carbonate, though in general this ratio is adequately 
expressed by the proportions of the properties of reaction. 

The calculations involved in the stages leading up to the deduction 
of the properties of reaction may seem long and tedious, but the 
value of the results should more than pay for the necessary labor. 
Adequate comparison is impossible until the analyses have been con¬ 
verted into ionic form; and when this step has been accomplished 
the labor of calculating the reacting values and deducing from them 
the properties of reaction is inconsiderable. 

SOURCE AND STATEMENT OF ANALYSES IN THIS REPORT. 

In order to give an adequate idea of the principles that seem to 
control the composition of the oil-field waters, 88 analyses selected 
from several hundred available for the writer’s study are included in 
this preliminary report. These analyses have been selected, first, 
according to their representation of the chemical variation encoun¬ 
tered; second, according to their position with regard to the oil; 
third, according to the probable accuracy of the analytical work; 
and, fourth, according to their geographic distribution. 

Of the 88 analyses given 30 were made by the Geological Survey, 
17 by the Standard Oil Co., 12 by the Kern Trading & Oil Co., and 
29 by industrial chemists. In most of those made by the Survey all 
the reported constituents were determined and the- percentage of 
error may be computed. The others are partial analyses, the alka¬ 
lies having been calculated by difference. The analyses made by 
the Standard Oil Co. and the Kern Trading & Oil Co. may be accepted 
as reliable and accurate within pretty close limits. The remaining 
analyses are believed to be reliable, but they were made only for 


CLASSIFICATION OF THE OIL-FIELD WATERS. 


41 


industrial purposes and doubtless according to different standards of 
accuracy. They afford a good idea of the general character of the 
water, and in most of them the error is probably less than 5 per 
cent. 

In the tables of analyses the properties of reaction are stated first, 
as they are believed to be the most suggestive as well as the most 
* convenient basis for general comparison. The sulphate salinity 
ratio, or the percentage of rS0 4 in rS0 4 + rCl, is included under the 
properties of reaction, and in certain types of water the ratio of the 
values of carbonate and bicarbonate to the sulphate value is also 
given. Below the reaction properties is given the analysis itself, 
stated in radicles in parts per million; this is a summary of the basic 
data on which any form of interpretation must rest. The analysis 
is also stated in reacting values in percentages, a form that admits 
direct comparison of the chemical values of the radicles but does not 
express the actual amounts present or the concentration of the solu¬ 
tion. Finally, those analyses which were not made by the Geological 
Survey and which were originally stated in hypothetical combina¬ 
tions in grains per United States gallon are given in the tables in 
their original form also. To some readers this form of statement 
may be the most familiar, but for rational scientific study one of the 
other forms is strongly recommended. 

CLASSIFICATION OF THE OIL-FIELD WATERS. 

DISTRIBUTION AND SIGNIFICANCE OF THE CONSTITUENTS. 

Alkalies (sodium and 'potassium ).—In most of the analyses in this 
report the alkalies, sodium and potassium, have not been separated, 
and as their chemical properties and distribution are similar they 
will be considered together. The alkalies are by far the most abun¬ 
dant bases in the oil-field waters, and in many of the deeper waters 
they and their equivalent acid radicles constitute over 95 per cent 
of the total mineral content. In surface waters the alkalies are less 
prominent, but in waters from depths of more than 250 or 300 feet 
they usually predominate over the other bases. The waters associ¬ 
ated with the oil in the western parts of the Coalinga, Midway, and 
Sunset fields contain the alkalies almost to the exclusion of the other 
bases. 

The great predominance of alkalies over the other bases is a notable 
feature of the composition of the waters of the oil fields of the west 
side of San Joaquin Valley, for in most regions of sedimentary rocks 
the waters are characterized by a moderate to low proportion of alka¬ 
lies. The salts of the alkalies are highly soluble and therefore are 
never deposited from saturated solution, except in arid regions, 
where they tend to accumulate at the surface as deposits of “alkali,” 


42 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

which is usually the sulphate. As the oil fields on the west side of 
the valley are located in a very arid region the relative prominence of 
the alkalies in the shallower waters is to be expected. Furthermore, 
in connate water (fossil sea water) the alkalies greatly predominate 
over the other bases, and as the deeper oil-field waters are partly 
or wholly of connate origin, two sets of conditions have combined to 
cause the high concentration of alkalies in the waters of the fields 
of the west side. In the Kern River field, on the east side of the 
valley, water is more plentiful, and the first condition is therefore 
less pronounced, but as the deeper waters are partly of connate 
origin their content of alkalies is fairly high. 

In sixteen of the analyses given below sodium and potassium have 
been determined separately. The potassium is generally present in 
very small proportion, the average ratio of sodium to potassium by 
weight being about 125 to 1. The average surface water in most 
regions contains by weight about one-fourth as much potassium as 
sodium, and ocean water only about one-thirtieth as much. 1 This 
discrepancy is due to the fact that when mixed solutions containing 
sodium and potassium are passed through soil or clay the potassium is 
almost wholly extracted and held, whereas the sodium is comparatively 
unaffected; 2 hence the potassium in ordinary surface waters is largely 
lost during their passage to the sea. Similarly,, if sea water is then 
entrapped in the sediments, the separation will continue still further 
and nearly all the potassium will he removed. This principle has 
thus operated to remove nearly all of the potassium in the connate 
and partly connate water of the oil fields. (See p. 93.) 

Alkaline earths (calcium and magnesium ).—In a few of the surface 
waters and shallow ground waters in the oil fields of the west side 
of the valley the alkaline earths exceed the alkalies, but in practically 
all the deeper waters their relative proportion is very low. This is 
due not only to the high concentration of the alkalies, as already 
explained, but also to the fact that the alkaline earths themselves 
are generally present in small actual amount. Large amounts of 
the earths can not be retained in waters in which more than a cer¬ 
tain value of carbonate or bicarbonate is present, and if this value 
is exceeded alkaline earth carbonates are precipitated from the solu¬ 
tion. In most of the shallower waters sulphate is high and carbonate 
low, and alkaline earths are therefore important constituents, but 
in the waters near the oil zone in the western parts of the Coalinga, 
Midway, and Sunset fields carbonate is high and the earths are 
accordingly low. In the connate waters in the central part of the 
Midway and Sunset fields chloride is very high and carbonate low, 


1 Clarke, F. W., The data of geochemistry, 3d ed.: U. S. Geol. Survey Bull. 61G, p. 138, 1916. 

2 Van Bemmelen, J. M., Das Absorptionsvermogen der Ackererde: Landw. Versuchs-Stationen (Ber¬ 
lin), vol. 21, pp. 135-191, 1878. 



CLASSIFICATION OF THE OIL-FIELD WATERS. 43 

and in this type of water the earths constitute as much as 10 per 
cent of the total mineral content. 

In sea water the ratio of magnesium to calcium by weight is about 
3, or if expressed in terms of reacting values, about 5. It is therefore 
interesting to note that in that type of oil-field water which the writer 
considers connate, and which closely resembles sea water in all other 
respects, the average ratio of the reacting values of magnesium to 
calcium is only 0.71. In some of the surface waters and shallower 
ground waters, especially those in the Coalinga field, the ratio is 
almost as high as in sea water, hut this is accounted for by the fact 
that these waters are a part of the drainage of areas in which ferro- 
magnesian (Jurassic) rocks outcrop. The deficiency of magnesium 
in the deeper waters can not be so easily explained. At high tem¬ 
peratures magnesium is deposited from solution as basic carbonate or 
hydrate, 1 and it is possible that the temperatures of 100° to 125° F., 
which prevail in the oil fields at depths of 1,000 to 3,000 feet, have 
had some effect in lowering the concentration of magnesium. It is 
also possible that the magnesium is removed as magnesium silicate, 
though no evidence was obtained in the field to support this view. 

In the table on page 92 are given the average ratios of magnesium 
to calcium in the several types of water in the Coalinga, Midway, and 
Sunset fields, only the analyses included in this report being repre¬ 
sented. The variations in these ratios are discussed in more detail 
below, but it may be pointed out here that the average ratio in the 
Coalinga field is considerably higher than in the Midway and Sunset 
fields, and that the ratio in the brine is only about half as great as in 
the other types of water. 

Sulphate .—In the normal ground waters everywhere on the west 
side of San Joaquin Valley sulphate is the predominating acid radicle, 
especially near the surface. In some of the shallow waters from the 
Coalinga field sulphate and its equivalent basic radicles constitute 
over 85 per cent of the total mineral content. Outside of the oil 
fields most of the deeper ground waters are also characterized by a 
high concentration of sulphate, but this figure bears no constant rela¬ 
tion to depth. Within the oil fields, however, sulphate decreases 
with increasing depth and practically disappears at a certain distance 
above the oil zone. Many of the waters associated with the oil do 
not contain even a trace of sulphate, and most of them carry less 
than 1 per cent, although in the Eastside Coalinga field sulphate is 
usually higher and some of the waters may contain as much as 5 per 
cent. The tables of analyses below show the ratio of sulphate to 
sulphate plus chloride by reacting value in all the waters discussed, 
and in many of these waters the ratio of sulphate to carbonate as well. 


i Davis, W. A., Studies of basic carbonates: Soc. Chem. Ind. Jour., vol. 25, p. 796,1906. 



44 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


The decrease of sulphate in the waters as the oil measures are 
approached, and its absence from the waters most closely associated 
with the oil, are believed to be the result of chemical reaction with 
constituents of the oil or gas. The sulphate is probably reduced to 
sulphide or hydrogen sulphide, which may either escape as gas or 
undergo oxidation to free sulphur and so he lost by precipitation. 
The reduction of the sulphate is presumably attended by the oxida¬ 
tion of an equivalent portion of the hydrocarbon material to carbonate 
or carbon dioxide. These reactions are discussed in more detail on 
pages 93-99. 

A great predominance of sulphate in the shallower waters is char¬ 
acteristic of most arid regions. Gypsum (calcium sulphate) is dis¬ 
seminated through the rocks and furnishes an abundant supply to 
the scanty volume of water percolating through them. In addition, 
much of the “alkali” that occurs as an incrustation or efflorescence 
in arid regions is sodium and magnesium sulphate. Ocean water 
contains about 2,700 parts per million of sulphate, or 7.7 per cent of 
the total mineral content. 

Chloride .—Chloride is a widespread constituent of terrestrial waters, 
but its concentration varies greatly. As the chlorides of all the com¬ 
mon bases are highly soluble in water, they are not important as 
rock-forming constituents and are concentrated chiefly in the ocean. 
A high concentration of chloride in ground water usually indicates 
that the water is partly of oceanic origin or that it has leached saline 
deposits. 

As already explained, the chloride in the oil-field waters is undoubt¬ 
edly of oceanic origin, and its concentration depends on the extent 
to which the connate sea water has been admixed with meteoric water 
carrying sulphate or carbonate. This admixture is controlled largely 
by the freedom of the circulation. Where the geologic structure is 
such as to prevent circulation the water is very salty, and in some 
localities the concentration of chloride in it is as great as in ocean 
water. Near the surface and near the outcrop of the beds the con¬ 
nate water has been largely replaced by meteoric water, and the con¬ 
centration of chloride is therefore much lower. 

Carbonate and bicarbonate .—In most industrial analyses no distinc¬ 
tion is made between carbonate and bicarbonate, the two being 
grouped under the head of carbonate. Under ordinary conditions 
the two are more or less interchangeable; carbonate may be regarded 
as the primary radicle from which, in the presence of carbon dioxide, 
bicarbonate is derived. If a sufficient amount of carbon dioxide is 
present all of the carbonate radicle may be converted to bicarbonate, 
but a slight increase in temperature or decrease in pressure may drive 
part of the carbon dioxide from the solution and thus cause a rever- 



CLASSIFICATION OF THE OIL-FIELD WATERS. 


45 


sion to carbonate. A solution of calcium bicarbonate, for example, 
yields calcium carbonate on boiling. The bicarbonates of calcium 
and magnesium are relatively soluble in water, whereas the normal 
carbonates are almost insoluble; hence, when the bicarbonate solu- 
tions are boiled and, by release of carbon dioxide, normal carbonate 
formed, most of the normal carbonate is thrown out as a precipitate 
or “scale.” The solubility of the alkaline earth radicle in the pres¬ 
ence of the carbonate radicle therefore depends largely on the con¬ 
centration or “partial pressure” of carbon dioxide in the solution. 
As most surface waters can dissolve enough carbon dioxide from the 
air to form bicarbonate exclusively, it is generally assumed that prac¬ 
tically all the carbonate reported in analyses of surface water and 
shallow ground water represents bicarbonate in the solution. 

Carbonate and bicarbonate are subordinate in amount to sulphate 
in most of the surface water on the west side of the San Joaquin 
Valley, and in the normal ground water are generally present in 
minor amount. In the waters associated with the oil, however, 
they are generally present in larger amounts, and when chloride is 
absent carbonate and bicarbonate constitute the only acid radicles. 
As chloride increases, however, these weak acid radicles decrease, 
and in the strong brines they are present only in very small amounts. 

Carbonate and bicarbonate have been differentiated in 30 of the 
analyses in this report. In 19 of these waters there is no carbonate, 
and in the remaining 11 the average carbonate value is only one- 
fifth of the bicarbonate value. Three of these 11 waters may be 
disregarded, for the carbonate reported probably formed during the 
time the samples had stood before being analyzed. It is perhaps 
noteworthy that of the remaining 8, in which carbonate and bicar¬ 
bonate exist together, 3 are surface waters and shallow ground water, 
and 5 are deep waters, either from or below the oil measures. Appar¬ 
ently in the zone directly above the oil, in which the carbonate waters 
are believed to have formed there is a sufficient excess of carbon 
dioxide to prevent the formation of normal carbonate. 

Sulphide .—Sulphide occurs in small amounts in many of the waters 
above the oil zone, and the presence of hydrogen sulphide has long 
been recognized by drillers as indicating a top water. The manner 
in which the sulphide is held in solution is usually not determined, 
but it is highly probable that in primary alkaline waters some of the 
sulphide is held in equilibrium by alkalies and perhaps by alkaline 
earths. In some waters the acid sulphide (bisulphide) radicle (HS) 
is doubtless present. Both the normal and acid sulphide, however, 
tend to form the gas, hydrogen sulphide (H 2 S), which is easily recog¬ 
nized by its odor, and to which directly the term sulphur water 
is due. 


46 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

Many waters from the Eastside Coalinga field carry considerable 
amounts of sulphide, which is reported in the industrial analyses as 
“sodium sulphide.” In these analyses, however, the alkalies are 
calculated by difference, and as the amount of alkalies present is not 
definitely known, the assumption that a sufficient amount is present 
to balance all of the sulphide is unwarranted. Although some of it 
may be balanced by alkalies, it is probable that much of it is actually 
present as the acid sulphide, which implies only half as much alkali 
as the normal sulphide, and that at least some of it is merely hydrogen 
sulphide. 

Sulphide in the oil-field waters of San Joaquin Valley is probably 
formed by the reduction of sulphate. This reaction generally takes 
place a short distance above the main oil zone, and whether the 
sulphide radicle is first formed or not it is certain that hydrogen 
sulphide is an important product. As hydrogen sulphide is a gas, 
it tends to rise to higher waters or to the surface, if it is free to migrate 
at all, and the current belief that “sulphur” waters are top waters is 
therefore well founded. Like most generalizations, however, it must 
be applied with discretion, for when sulphate water percolates into 
the brown shale below the oil measures, as along the western edge of 
the Midway field, and there encounters small amounts of oil or gas, 
the sulphate may be partly reduced to sulphide and a sulphur water 
thus formed far below the oil zone. Some of the most pronounced 
sulphur waters in the oil fields are obtained from wells located near 
the outcrop of the oil sands, which draw their water from the strata 
below the oil. 

Iron and aluminum .—Iron and aluminum differ from the constitu¬ 
ents already discussed in that they occur in most waters simply as 
hydrated oxides, which are supposed to be in the colloidal state 
rather than in true solution. They are rarely present in large 
amounts and generally do not affect the chemical aspects of the 
water. 

In a great many natural waters much the larger part of the “iron 
oxide and alumina” reported is iron oxide, and the amount of 
alumina is very small. In a few of the analyses given in this report 
the two have been separately determined, and in these oil-field waters 
the reverse seems to be more generally true. The iron is usually very 
low, although it varies widely. It seems probable that the low con¬ 
tent of iron is due to the fact that in the presence of hydrogen sulphide 
it has reverted from the colloidal state and formed iron sulphide, 
which being only slightly soluble has been mostly precipitated. On 
the other hand, the unusually large amounts of iron sometimes found 
are probably derived through the corrosion of the iron casing of 
wells, and some of this iron may be present not as colloid but in true 
solution. 


CLASSIFICATION OF THE OIL-FIELD WATERS. 


47 


Silica. —Silicon is nearly always present as the colloidal oxide 
(silica) and may therefore be disregarded in a study of the reactive 
properties of the water. In primary alkaline waters it may enter 
the solution as silicate, hut probably soon breaks down into the 
colloidal form (Si0 2 ). It varies greatly in amount in the oil-field 
waters, hut averages higher in primary alkaline waters than in brine. 

Other constituents. —Several mineral constituents in addition to 
those already mentioned are probably present in the oil-field waters. 
Nitrate has been sought in 27 of the samples here discussed and 
has been found in only 5, of which 4 are surface waters. A small 
quantity of boron was found in the one sample tested for it. Bro¬ 
mine and iodine have been detected in some of the oil-field brines, 
and the iodine was determined quantitatively in one sample. (See 
analysis 58, Table 9, p. 74.) Iodine in unusually large amounts 
in several samples of brine from the Midway and Sunset fields was 
also reported many years ago by Watts. 1 

Total mineral solids. —The total mineral solids present in a given 
quantity of water, or the concentration of the solution, varies widely 
in the different oil-field waters. In the surface water and shallow 
ground water of the Kern River field the content of dissolved mineral 
matter is lowest and is generally less than 200 parts per million. 
All the shallower waters examined in the fields of the west side of 
the valley contain more than 300 parts, and most of them contain 
between 1,000 and 4,000 parts. The concentration in general in¬ 
creases with depth; most of the deeper waters of the Kern River 
field contain between 1,500 and 4,000 parts, and those of the fields 
on the west side of the valley between 8,000 and 40,000 parts. 
Although the concentration of the various types of water is fairly 
regular, individual samples may show considerable variation. 

In the tables of analyses given below the concentration is repre¬ 
sented simply by the totals of the constituents reported except 
when bicarbonate is shown. Bicarbonate is unstable and tends to 
break down into carbonate when the solution is evaporated to dry¬ 
ness; hence, in accordance with convention, the bicarbonate radicle 
is not given its full value in the total but appears as carbonate. 

Organic and volatile matter. —The figure given in most industrial 
analyses under the heading "organic and volatile” represents the 
loss in weight when the solid matter obtained on evaporation is 
heated to redness. It consists chiefly of carbon dioxide and whatever 
organic or hydrocarbon matter was present in the water. Many of 
the primary alkaline waters that have been closely associated with 
the oil contain dissolved organic matter in the form of petroleum 
acids, which would be included in this determination. However, most 

i Watts, W. L., The gas and petroleum yielding formations of the Central Valley of California: California 
State Min. Bur. Bull. 3, pp. 90-91, 1874. 




48 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

samples of oil-field water as submitted for analysis contain a small 
amount of oil floating on the surface, and as this oil is also included 
in the determination it is evident that the figure has no exact value. 
It has therefore been omitted from the tables of analyses published 
in this report. 

CRITERIA FOR COMPARISON. 

Natural waters differ widely in the chemical character of the sub¬ 
stances dissolved in them, and several different types of water may be 
found in nearly every region. However, the different varieties tend 
to mingle and react through constant circulation, until the pure 
types may be less common than the gradations between them. 
Moreover, if the rocks differ irregularly in composition, the waters, 
whose character reflects that of the rocks with which they come in 
contact, must bo similarly different. In many areas, therefore, the 
natural waters present such infinite variation in chemical composi¬ 
tion that even though it is recognized that a certain type is normally 
characteristic of a certain locality or formation it is impossible to 
draw a definite line of demarcation. 

In the oil fields of San Joaquin Valley, however, special condi¬ 
tions have led to the formation of very distinct types of water. As 
the transitions from one type to another occur within relatively 
short distances fairly definite zones or localities that are characterized 
by the same type of water can be established. The development of 
these distinct types has been due partly to the influence of the oil 
and gas, and the oil-field waters therefore present contrasts that are 
lacking in the waters of most areas. 

The three groups of salts most commonly dissolved in natural 
waters are chlorides, sulphates, and carbonates, and in the oil fields 
there are waters which contain any one of the three almost to the 
exclusion of the others. The concentration of chloride has already 
been shown to be governed by physical conditions, such as freedom 
of circulation; and since these conditions are more or less local and 
irregular the content of chloride furnishes the least satisfactory basis 
for the comparison of waters. The relative proportion of sulphate 
and carbonate, on the other hand, is influenced by fairly definite 
chemical reactions that take place only near accumulations of oil and 
gas; hence the carbonate-sulphate ratio may serve as an indication 
of the position of the water with respect to hydrocarbons. Study of 
the carbonate-sulphate ratio in waters in a developed field, in which 
the relations of oil, gas, and water have been discovered, forms an 
excellent criterion for differentiation and a tangible basis for § system 
of classification; in an undeveloped field, on the other hand, it may be 
used as an indication of the presence or absence of hydrocarbons 
near by. 


CLASSIFICATION OF THE OIL-FIELD WATERS. 49 

I 

It is often difficult, owing to the wide variations in the chemical 
character of natural waters, to distinguish without careful study 
the significant differences from the more or less fortuitous, or more 
properly, the differences that are due to determinable and fixed 
conditions from those which result from changing or indeterminable 
conditions. The carbonate-sulphate ratio is a significant criterion, 
for it is apparently governed chiefly by the position of the water 
with regard to the oil; but the ratio of sodium to potassium, for 
example, is controlled by factors that are indeterminable or not 
well understood. These ratios are interesting and are valuable for 
some purposes, but they involve too much speculation to be of basic 
importance in a study of oil-field waters. Unfortunately, several 
investigators who have already undertaken the study of the Cali¬ 
fornia oil-field waters have deemed it unnecessary to make complete 
analyses, and have based their estimates of the position of a water 
upon such isolated criteria as the concentration of chloride, the 
ratio of magnesium to calcium, or the presence or absence of such rare 
constituents as lithium or iodide. Some of the conclusions based on 
these incomplete studies have proved erroneous, and the writer en¬ 
countered considerable skepticism among the oil operators as to the 
practical value of chemical studies of the oil-field waters. The more 
complete information now available furnishes a better basis for con¬ 
clusions, both as to the influence of hydrocarbon material on the 
composition of a water and also as to the genetic relations of the 
waters themselves. 

PROPOSED CLASSIFICATION. 

Since all natural waters are mixtures, it is impossible to classify 
them rigorously, and any system of classification is a matter of con¬ 
venience rather than of fixed principles. For practical convenience 
it is evident that oil-field waters should be classified as far as possible 
according to their position in relation to the oil. As waters near the 
oil measures differ in composition from those nearer the surface, a 
classification based directly on the chemical character of the waters 
and indirectly on their position in relation to the oil may be made. 

The sulphate-carbonate ratio furnishes a convenient basis for classi¬ 
fying waters that contain only minor amounts of chloride, but in 
most localities chloride must be taken into account. Thus, in the 
Midway field chloride may be far more prominent than sulphate in the 
shallow waters, and in the deeper waters may be present almost to 
the exclusion of carbonate. Under these circumstances the replace¬ 
ment of sulphate by carbonate is less striking. 

The relation of the various types becomes clearer when their origin 
is considered. The sulphate water, being the normal ground water 


60439°—Bull. 653—17-4 



50 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

of the region, is typically of meteoric origin; that is, it is rain water 
that has entered the ground and dissolved some of the more soluble 
constituents of the rocks. The salt water, however, is typically of 
connate origin and represents sea water that has been entrapped and 
retained in the sediments, dissolving some of their constituents and 
losing some of its own, but in the main retaining its original compo¬ 
sition. The connate water is relatively stationary or stagnant, but 
the meteoric water is to some extent continually descending from the 
surface and mixing with the connate water. Both types are simi¬ 
larly affected by constituents of the oil or gas, sulphate being removed 
and carbonate introduced, but whereas the composition of the mete¬ 
oric water is entirely reversed by this process, the pure connate water, 
which contains at the start only a small proportion of sulphate, is 
much less conspicuously altered. Most waters are mixtures of con¬ 
nate and meteoric types, and the extent of their alteration therefore 
depends on the proportions of the mixture. Two sets of forces are 
at work; the one leads to the mixing of two opposing types of water 
in various proportions, and the other induces in both types chemical 
changes which are similar in kind but different in degree. 

This distinction between meteoric and connate waters is valuable 
in forming a conception of the genetic relations of the oil-field waters, 
but it may be well to reiterate that it can not be strictly applied in 
the field. (See p. 22.) Connate marine water is readily identified by 
its high content of chloride, but the connate fresh water which the 
rocks may contain can not be distinguished from meteoric water. 
Although the terms strictly represent origin, in actual practice they 
are necessarily reduced to a chemical basis and are so used in this 
report. As the reactions of a water with hydrocarbon material depend 
on its chemical character rather than on its origin, the precise genetic 
classification is chiefly of theoretic value. 

An attempt has been made to present graphically the chemical rela¬ 
tions of the oil-field waters in figure 3. In this diagram the meteoric 
water is shown as entering the rocks and percolating down toward the 
oil, undergoing a modification and finally a reversal of its chemical 
character; the connate water is shown as already existing in the 
rocks but undergoing a similar alteration as the oil is approached; 
and the two classes are shown as converging and mixing in various 
proportions. The three broad divisions of both types and their mix¬ 
tures, according to their relation to the oil, may be called normal, 
modified, and altered. Normal ground water is that which contains 
a normal percentage of sulphate; this percentage is generally high, 
for this type is either pure meteoric water or a mixture in which 
meteoric water predominates. Strictly normal or unaltered connate 
water has not been encountered. The modified group, characterized 
by a percentage of sulphate lower than normal, may be either meteoric 


CLASSIFICATION OF THE OIL-FIELD WATERS. 


51 


or connate but is generally a mixture in which meteoric water pre¬ 
dominates. The waters of the altered group contain practically no 
sulphate; they may be either meteoric or connate, or a mixture of 
che two. Many analyses of altered waters are available, and since 
the two extremes, meteoric and connate, are well represented, three 
types of altered water may be distinguished. Altered water of mete¬ 
oric origin may be called the reversed type; altered connate water may 


Meteoric 



Mixed 

/-ypz 


Figure 3.—Diagram illustrating relation of oil-field waters of the meteoric and connate types, and their 

alteration as the oil zone is approached. 


be called simply brine, and altered mixtures of the two may be called 
the mixed type. This classification may be summarized as follows: 

Group 1. —Normal, strongly sulphate water (typically of meteoric origin). 

Group 2. —Modified, less strongly sulphate water (may be either meteoric or 
connate but is commonly a mixture in which meteoric water predominates). 

Group 3. —Altered, practically sulphate-free water (meteoric and connate 
waters and mixtures of the two). 

Reversed (carbonate water, originally meteoric). 

Brine (chloride water, originally connate). 

Mixed (chloride-carbonate water). 

This is primarily a classification of the ground waters, but for con¬ 
venience surface waters may be included in the normal group. The 
normal group includes most shallow ground water, but the depth to 
which normal waters descend depends principally on the depth of 
the oil zone. Modified waters occupy the zone below the normal 
zone and include the sulphur waters often found some distance above 
the oil. The thickness of the modified zone is generally several 
hundred feet, but it is variable and no definite limits can be assigned. 
In the Westside Coalinga field the oil measures occur at the base of 
the modified zone, and the normal and modified groups are therefore 





52 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

coincident with the “top water,” but in the Midway-Sunset fields sev¬ 
eral hundred feet of strata containing altered water intervene be¬ 
tween the base of the modified zone and the top of the oil measures. 
All the “bottom water” or “edge water” examined is of the altered 
type, and in general this type extends for several thousand feet 
below the oil measures. 

As most of these waters are mixtures of meteoric and connate 
water their degree of alteration as the oil is approached is different. 
Normal connate water would contain by reacting value about 9.2 
per cent of sulphate, so that a water of this class containing only 3 
per cent of sulphate might reasonably be referred to the modified 
group; a normal meteoric water, on the other hand, may contain 45 
per cent of sulphate, hence a water of meteoric origin containing 
only 15 per cent would naturally fall in the modified group also. 
Furthermore, the composition of normal ground water is different 
in different areas, and therefore the modified and altered types 
derived from it will differ in composition. 

Any limits assigned these groups evidently must be arbitrary and 
of only local value, but for the waters in the oil fields on the west 
side of San Joaquin Valley the following limits are suggested:. 

1. Normal group: 

Secondary salinity present, sulphate high; ratio of carbonate to sul¬ 
phate generally less than 1; alkaline earths may be prominent. 

2. Modified group: 

Chiefly of meteoric origin. Primary alkalinity present; sulphate 
salinity greater than 15 per cent of the total salinity; ratio of car¬ 
bonate to sulphate generally between 1 and 15; alkaline earths gen¬ 
erally subordinate to alkalies. 

Chiefly of connate origin. Secondary salinity present; sulphate salinity 
greater than 1 per cent of the total salinity; alkaline earths generally 
less than 10 per cent of total reacting value. 

3. Altered group: 

Reversed type. Primary alkalinity greater than 50 per cent; sulphate 
salinity less than 15 per cent of the total salinity; ratio of carbonate 
to sulphate generally greater than 15; alkaline earths generally less 
than 8 per cent of total reacting value. 

Brine. Secondary salinity present; sulphate salinity less than 0.5 per 
cent of total salinity; alkaline earths generally between 2 and 10 
per cent. 

Mixed type. Primary alkalinity less than 50 per cent; sulphate salinity 
less than 1 per cent of total salinity; alkaline earths generally about 
1 or 2 per cent. 

These limits have been observed as far as possible in grouping the 
analyses. The groups are not mutually exclusive, however, and 
when a water falls in two groups its classification has been decided 
by comparison with the waters above and below it. 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 53 

COMPOSITION OF THE OIE-FIERD WATERS. 

DESCRIPTION OF THE TYPES. 

GENERAL COMPARISON. 

The analyses of the oil-field waters are discussed and the general 
characteristics of each type are pointed out in the following sections. 
Seventy-three of the analyses given represent the types of water 
found in the Coalinga, Midway, and Sunset oil fields, and these have 
been classified in Tables 1 to 11. In Tables 12 and 13 groups of 
analyses are arranged to show the variation in water from different 
depths. Table 14 contains analyses of types of water from the Kern 
River, Lost Hills, and McKittrick fields, which are introduced to 
show that the same principles apparently govern the character of 
the waters in those localities. Although the classification is directly 
chemical it is indirectly based on the position of the water in rela¬ 
tion to the oil, so that the tables group waters according to their 
horizon as well as according to their composition. A number of 
waters have been included that differ in one particular or another 
from the average for the type, or, if they conform to the type, they 
occupy an apparently anomalous position, and these exceptions are 
explained as far as possible in the discussion. Undue stress has per¬ 
haps been laid on these rarer occurrences, but it has seemed desirable 
to point out at this time such variations from the normal as are most 
likely to be encountered. 

In order to sum up the more important variations in the chemical 
character of the waters and to show graphically their genetic rela¬ 
tions, all the analyses given in this paper have been plotted in figure 4. 
In this diagram the two incompatible properties of waters—sec¬ 
ondary salinity or permanent hardness and primary alkalinity— 
expressed in per cent, represent the horizontal axis to the left and 
right respectively of a common line. All the secondary saline waters 
therefore fall in the left section of the chart and all of the primary 
alkaline in the right. On the vertical axis has been plotted the 
sulphate salinity ratio (per cent of rS0 4 in rS0 4 + rCl), and accord¬ 
ingly all of the sulphate-free waters associated with the oil appear 
along the base line of the chart. The approximate concentration 
(total mineral solids) in parts per million of each water is shown by 
symbols. 

It is believed that the properties selected to represent the axes of 
this diagram furnish the most satisfactory criteria for a broad com¬ 
parison of oil-field waters. It will be noted that most of the surface 
waters, high in sulphate and in alkaline earths, fall in the upper left- 
hand corner of the chart. The normal ground waters of meteoric 


Secondary salinity ("permanent hardness") Primary alkalinity ("softness”) 




54 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 



Figure 4.—Chart showing chemical relations of the oil-field waters. 




























































COMPOSITION OF THE OIL-FIELD WATERS. 


55 


origin show a somewhat lower percentage of secondary salinity hut 
a fairly high proportion of sulphate, and therefore fall to the right 
of and somewhat below the surface waters. The waters closer to the 
oil measures,- being lower in sulphate and higher in carbonate, fall 
still farther in the same direction, which is indicated by an arrow. In 
the lower right-hand corner of the chart are the altered waters of 
meteoric origin, forming the reversed type. In the course of their 
progressive alteration from the surface downward these meteoric 
waters therefore fall along a line extending diagonally across the 
whole chart. Their concentration is never high, although the deeper 
waters naturally contain more dissolved mineral matter than those 
near the surface. 

The alteration of the connate waters proceeds in the same direction 
but along another course. For purposes of comparison an analysis 
of ocean water (analysis 52) has been plotted, and it will be noted 
that all of the oil-field brines fall below it and somewhat to the right, 
indicating a loss of sulphate and a decrease in secondary salinity. 
Analyses 25 and 87 may be regarded as intermediate and as repre¬ 
senting modified connate waters. The concentration of all these 
brines is fairly uniform, being close to that of sea water. As sug¬ 
gested by the length of the arrows, the amount of alteration under¬ 
gone by the connate waters in their transition to the brine type is 
very small as compared with the almost complete reversal of com¬ 
position undergone by the meteoric waters. 

Between the chiefly meteoric waters and the chiefly connate fall 
the various mixtures. Only four analyses of normal and modified 
waters of distinctly mixed origin are available, but in the group of 
altered waters variously proportioned mixtures are common. Nearly 
every gradation from typical brine to the practically pure carbonate 
water represented by analysis 36 is shown. The concentration shows 
a similar gradation from more than 15,000 parts per million in the 
brines to less than 5,000 parts in waters of the reversed type. 

SURFACE WATER. 

Representative analyses of surface water from the Coalinga, 
Midwav, and Sunset fields are shown in Table 1. Although these 
waters differ widely in some respects, all of them except No. 6 have 
certain fundamental properties in common. It will be noted that 
in all of them, except No. 6, the sulphate salinity ratio is over 80 per 
cent and that all of them are characterized by secondary salinity. 
In a?l of them the primary salinity is 50 per cent or less, the secondary 
salinity between 15 and 70 per cent, and the secondary alkalinity 
between 11 and 62 per cent. In other words the alkaline earths 
exceed the alkalies and sulphate is generally the predominating acid 


56 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


radicle. The concentration ranges between 314 parts per million and 
8,790 parts. 

The water of Los Gatos and Diaz creeks in the Coalinga field 
(analyses 1 and 2) is the drainage of a district in which igneous and 
metamorphic as well as sedimentary rocks outcrop. These waters 
differ from the other surface types in their higher content of alkalies 
and in the marked predominance of the magnesium value over that 
of calcium. Crocker Spring (analysis 4) in the Midway field is in¬ 
teresting as the most extreme secondary saline type encountered, the 
predominating dissolved salt being gypsum. (See fig. 4.) Bitter- 
water Creek (No. 5) is characterized by high sulphate and by an 
extremely large amount of dissolved solids, greater than that carried 
by many of the deeper waters. The Kern County Land Co. Spring 
(analysis 6), on the other hand, is characterized by a lower proportion 
of dissolved solids than any of the other waters of the west side, 
which may be due to the fact that it issues near a fault between 
granite and sedimentary rocks. Chiefly because of its low concen¬ 
tration it is characterized by a much higher proportion of secondary 
alkalinity than any of the others. 

Analysis 83 (Table 14, p. 85) shows the average composition of 
Kern River on the east side of San Joaquin Valley. As this water is 
the drainage of a region underlain by granites and other resistant 
rocks it is characterized by primary alkalinity rather than secondary 
salinity, and contains a relatively low proportion of sulphate. It is 
a very dilute solution dominantly secondary alkaline in character. 


COMPOSITION OP THE OlL-PIELD WATERS. 57 

Table 1 . —Analyses of surface water from the Coalinga, Midway , and Sunset oil fields, 

Cal. 


PROPERTIES OF REACTION IN PER CENT. 

Primary salinity. 

Secondary salinity. 

Primary alkalinity. 

Secondary alkalinity. 

Per cent of rS0 4 in rS0 4 +rCl. 

CONSTITUENTS IN PARTS PER MILLION. 

Sodium (Na). 

Potassium (K). 

Calcium (Ca). 

Magnesium (Mg). 

Iron oxide (Fe 203 > and alumina (AI 2 O 3 ) 

Sulphate (S0 4 ). 

Nitrate (N0 3 ). 

Chloride (Cl). 

Carbonate (C0 3 ). 

Bicarbonate (HC0 3 ). 

Silica (SiO?). 


REACTING VALUES IN PER CENT. 

Alkalies: 

Sodium (rNa). 

Potassium (rK). 

Alkaline earths: 

Calcium (rCa). 

Magnesium (rMg). 

Strong acids: 

Sulphate (rS0 4 ). 

Nitrate (rN0 3 ). 

Chloride (rCl). 

Weak acids: 

Carbonate (rC0 3 ). 

Bicarbonate (rHC0 3 ). 

ANALYSIS AS REPORTED, c 

Sodium sulphate. 

Sodium chloride. 

Calcium sulphate. 

Calcium carbonate. 

Magnesium sulphate. 

Magnesium carbonate. 

Iron oxide and alumina. 

Silica.v. 


1 

2 

3 

4 

5 

6 

7 

40.8 

50.0 

44.4 

14.4 

45.4 

19.6 

28.4 

16.0 

38.4 

22 

70.4 

48 

18.8 

43.6 

0 

0 

0 

0 

0 

0 

0 

43.2 

11.6 

33.6 

15.2 

6.6 

61.6 

28.0 

81.4 

95.7 

86.1 

94.9 

93.4 

66.1 

90.5 

ol85 

a 668 

} 216 

117 

1,409 

23 

| a 112 

40 

248 

92 

444 

630 

56 

138 

117 

203 

87 

107 

511 

16 

66 

4.5 






1.9 

436 

2,361 

580 

1,393 

5,638 

47 

538 



Trace. 

5 

Trace. 

30 


75 

78 

70 

53 

300 

18 

42 

b 255 

5 203 

0 

0 

30 

7.2 

5 144 



433 

335 

475 

178 


4.4 

13 

'87 

50 

38 

29 

12 

1,116.9 

3,774 

1,345 

2,334 

8,790 

314.2 

1,053.9 

a 20.4 

a 25.0 

} 22.2 

7.2 

22.7 

9.8 

( ol4.2 

5.1 

10.6 

10.9 

30.7 

11.7 

27.4 

20.1 

24.5 

14.4 

16.9 

12.1 

15.6 

12.8 

15.7 

23.1 

42.3 

28.6 

40.2 

43.6 

9.6 

32.6 




.1 


4.7 


5.3 

1.9 

4.6 

2.1 

3.1 

4.9 

3.4 

521.6 

55.8 

.0 

.0 

.4 

2.3 

5 14.0 



16.8 

7.6 

2.9 

28.5 









24.53 

111.30 





15.30 

7.21 

7.51 





4.06 

27.28 





8.36 

5.85 

16.10 





14.04 

11.17 

54.49 





19.04 

15.99 

3.06 






.26 






.11 

.26 

.76 





.69 







65.27 

220.50 





61.60 







/ 


a Reported and calculated as sodium but includes potassium. 
b Reported and calculated as carbonate but probably in part bicarbonate, 
c In hypothetic combinations, in grains per U. S. gallon. 


^^Los Gatos Creek> T 2 o S., R. 14 E. Analyst, Kern Trading & Oil Co. 

2. Diaz Creek, T. 19 S., R. 14 E., sampled above junction with Los Gatos Creek. Analyst, Kern 
Trading & Oil Co. 

Midway^field^ g . sec 2 T 30 g > R 2 1 E. Spring is in Santa Margarita (?) formation, but source of 
water may be affected by near-by fault. Sampled by G. S. Rogers, September, 1915. 

S C Dinsmore ** 

4. Crocker Spring, sec. 18, T. 31 S., R. 22 E. Spring is in shale of Monterey group. 

Rogers, September, 1915. Analyst, S. C. Dinsmore. 

Sunset^fleld^water Creek> seC- 29; T u n., R. 24 W. Sampled by G. S. Rogers, September, 1915. Analyst, 

6 Kern County 1 2 * 4 * * 7 Land Co. Spring in west corner of San Emigdio land grant. Sampled from pipe line 
of Western Minerals Co. by G. S. Rogers, September, 1915. Analyst S. c. Dinsmore. 

7. San Emigdio Creek, San Emigdio land grant. Analyst, Standard Oil Co., June, 1910. 


Analyst, 
Sampled by G. S. 























































































58 


OIL-FIELD WATERS 11ST SAN JOAQUIN VALLEY, CAL. 


NORMAL GROUND WATER. 

Shallow water wells —Analyses of normal ground water from shallow 
water wells in the Coalinga, Midway, and Sunset fields are given in 
Table 2. These waters, like the surface waters, show a rather wide 
range in composition. All of them except Nos. 9 and 14 are secondary 
saline waters, but the secondary salinity is generally lower than in 
the surface waters and the primary salinity higher. Chloride and 
the alkalies are somewhat higher, especially in the waters from the 
Midway field. 

Analyses 8 and 9 represent shallow well waters from the Eastside 
Coalinga field. They are very similar in composition, though on 
opposite sides of the dividing line, No. 8 being slightly secondary 
saline and No. 9 showing 1.8 per cent of primary alkalinity. Analysis 
10 shows the general composition of the water in many of the shallow 
wells in the northern part of the Westside Coalinga field. Nos. 11 
and 12 are very similar to surface waters, although in No. 12 chloride 
is high. Analyses 13 and 14 represent waters from the Midway-Sun¬ 
set field, both of which are characterized by high chloride. No. 14 
represents a mixed water derived from two sands, 450 feet apart, the 
deeper of which has probably contributed the small percentage of 
primary alkalinity present. 

Analyses 84 and 87 (Table 14, p. 85) represent shallow ground 
, waters of very different types from the Kern River and Lost Hills 
fields. No. 84 is similar to the water of Kern River, already dis¬ 
cussed, differing from it only as the shallow ground waters of the 
west side of the valley differ from the surface waters of that region. 
No. 87 is water from a well 180 feet deep, located somewhat west of 
the axis of the Lost Hills anticline. Its properties are very close to 
those of sea water (see fig. 4, p. 54), the chief differences being a 
slight reduction in sulphate and a very small increase in carbonate. 
The concentration is exceptionally high for a shallow water, being 
over a third of that of sea water. This water is distinctly a connate 
type, and the slight alteration that it has undergone is remarkable 
in view of its proximity to the surface. 

Oil wells (top water ).—Tables 3 and 4 contain twelve ana.yses of 
normal ground water or top water from oil wells in the Coalinga and 
Midway-Sunset fields. There is, of course, no essential difference 
between these waters and those from shallow water wells, the sepa¬ 
ration being merely one of convenience. However, most of these 
waters are deeper than those shown in Table 2, and consequently 
the primary salinity is generally higher and the secondary salinity 
and secondary alkalinity lower. The concentration is generally 
higher, and in several waters is very high. 


COMPOSITION OF THE OIL-FIELD WATERS. 


59 


Table 2. —Analyses of normal ground water from shallow-water wells in the Coalinga, 

Midway , and Sunset oil fields, Cal. 


PROPERTIES OF REACTION IN PER CENT. 

Primary salinity. 

Secondary salinity. 

Primary alkalinity. 

Secondary alkalinity. 


Per cent of rS0 4 in rS0 4 +rCI. 

CONSTITUENTS IN PARTS PER MILLION. 

Sodium (Na). 

Potassium (K). 

Calcium (Ca). 

Magnesium (Mg). 


Sulphate (S0 4 ). 

Chloride (Cl). 

Carbonate (C0 3 ). 

Bicarbonate (HC0 3 ). 
Silica (SiOg). 


REACTING VALUES IN PER CENT. 
Alkalies: 

Sodium (rNa). 

Potassium (rK). 

Alkaline earths: 

Calcium (rCa). 

Magnesium (rMg). 

Strong acids: 

Sulphate (rS0 4 ). 

Chloride (rCl). 

Weak acids: 

Carbonate (rC0 3 ). 

Bicarbonate (rHC0 3 ). 


ANALYSIS AS REPORTED, c 


Sodium sulphate. 

Sodium chloride. 

Sodium carbonate. 

Calcium sulphate. 

Calcium carbonate. 

Magnesium sulphate.... 
Magnesium carbonate... 
Iron oxide and alumina. 
Silica. 


8 

9 

10 

11 

12 

13 

14 

78.0 

80.2 

72 

37.2 

58.2 

76.0 

87.4 

4.2 

.0 

25 

43.4 

37.6 

12.6 

0 

.0 

1.8 

0 

.0 

0 

0 

3.4 

17.8 

18.0 

3 

19.4 

4.2 

11.4 

9.2 

88.5 

87.0 

79 

72.7 

43.6 

26.6 

60.2 

a 470 

a 457 

a 981 

a 198 

a 980 

a 254 

719 







9.5 

59 

45 

297 

166 

257 

61 

39 

34 

26 

21 

75 

217 

6 

22 

Trace. 

7 

48 


3.3 



914 

814 

2,177 

649 

1,473 

166 

879 

88 

88 

423 

180 

1,399 

335 

429 

6 140 

6 143 

6 54 

6 134 

6 91 

6 51 

32 







170 

44 

61 

21 


45 

26 

44 

1,749 

1,641 

4,022 

1,402 

4, 465.3 

899 

2,257.5 

a 39.0 

a 41.0 

a 36.0 

a 18.6 

a 29.1 

38.0 

45.0 







.4 

5.6 

4.6 

12.5 

18.0 

8.7 

10.3 

2.8 

5.4 

4.4 

1.5 

13.4 

12.2 

1.7 

2.6 

36.4 

35.0 

38.4 

29.3 

20.9 

11.8 

26.3 

4.7 

5.1 

10.1 

11.0 

27.0 

32.5 

17.4 

6 8.9 

6 9-9 

61.5 

6 9.7 

6 2.1 

5.7 

1.5 







4.0 








74 30 

70.35 

126.49 

14.56 

11.03 



8.48 

8.50 

40.82 

17.40 

134.91 



1.27 

.58 

1.20 




55.96 

15.20 

45.78 



8 56 

6.60 

2.19 

13.10 

3.79 



4 01 

2.96 

21.70 

57.95 



4 22 

5.20 

2.17 

3.36 




.41 

1.25 


.19 



2.56 

3.57 

2.82 


2.62 







102.13 

95.90 

235.24 

81.96 

260.83 




a Reported and calculated as sodium but includes potassium. 
b Reported and calculated as carbonate but probably in part bicarbonate, 
c In hypothetic combinations, in grains per U. S. gallon. 

Coalmga fielded Qfl Cq water well 3> seC- 2 8, T. 19 S., R. 15 E. Analyst, Standard Oil Co., September, 

9. Standard Oil Co. water well 2, sec. 36, T. 19 S., R. 15 E. Depth, 444 ieet. Analyst, Standard 

10. Associated Pipeline Co., shallow water well at station 1, sec. 18, T. 20 S.,R. 15 E. Analyst, Smith, 

Emery & Co. Authority, Associated Oil Co. • , ^ j T , 

11. Traders Oil Co. water well, sec. 24, T. 20 S., R. 14 E. Depth, 85 feet. Analyst, L. J. Stabler, 

May, 1909. Authority, Traders Oil Co - m „ ,, .. „ . . . „ ... „ £ n 

12. California Oil & Gas Co., water well 1, sec. 6, T. 21 S., R. 15 E. Analyst, Smith Emery & Co. 

MidwayanBJunsetfieWs.. gec> 5> T 31 s> R 25 E. Analyst, Kern Trading & Oil Co., Jan. 1, 

1913 

14 Midway Northern Oil Co. water well, sec. 32, T. 12 N., R. 23 W. Water from sands at 350 and 
790 feet. Sampled by G. S. Rogers, August, 1914. Analyst, Chase 1 aimer. 

Most of these waters may be readily distinguished from surface 
waters, but their distinction from the modified waters beneath 
them is less easy. As shown by figure 4, the shallower waters are 























































































60 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


secondary saline in character and high in sulphate, whereas those 
near the oil are primary alkaline and free from sulphate. However, 
there are many intermediate types which show primary alkalinity 
and still retain a fairly high proportion of sulphate. For con¬ 
venience in discussing the waters of the fields of the west side the 
secondary saline waters high in sulphate have been referred to the 
normal group and those of primary alkaline character containing 
considerable sulphate to the modified group. The line of demarca¬ 
tion is therefore assumed to be the point at which secondary salinity 
disappears and primary alkalinity appears. As a rule this division 
is justified, for the decrease of secondary salinity is probably due as 
much to the normal increase of alkalies with depth as to actual 
decrease of sulphate. However, when sulphate is very high and the 
alkalies are proportionately less abundant than usual, the property 
of secondary salinity may be retained after some of the sulphate 
has been removed. Analyses 21 and 26, for example, represent 
sulphur waters, the hydrogen sulphide being presumably due to 
the reduction of some of the sulphate, yet both of these waters are 
secondary saline and are therefore grouped with normal types. As 
an additional criterion of the alteration of the waters the ratio of 
carbonate to sulphate is shown in Tables 3 to 7. It will be noted 
that in all of the analyses in Tables 3 and 4 except Nos. 19 and 21 
this ratio is less than 0.25, and that No. 21 is a sulphur water which 
has doubtless been somewhat modified. This ratio explains another 
apparent inconsistency in Table 3, namely, the inclusion of No. 17, 
a primary alkaline water, with the normal secondary saline waters. 
In this water the sulphate is extremely high in comparison with 
both chloride and carbonate and the appearance of primary alkalinity 
is due rather to the abnormally low proportion of alkaline earths than 
to any loss of sulphate. As already stated, no single property or 
constituent of a natural water can be a universal criterion of its 
relation to the oil. 

Analyses 15 and 16 represent the ordinary top water in the 
northern part of the Eastside Coalinga field. The exact position of 
these waters is not known, but from the higher primary salinity and 
concentration of No. 16 it is thought to be somewhat the deeper of 
the two. No. 18, from the Westside Coalinga field, is a water very 
similar in composition to the last but of exceptionally high con¬ 
centration. It is a sulphur water and therefore has probably been 
slightly influenced by the hydrocarbons, though the proportion of 
sulphate as compared with both carbonate and chloride is still very 
high. No. 19 represents an unusual top water whose exact horizon 
is unknown. Its concentration is very much lower than that of 
most waters of the west side and therefore the sparingly soluble bicar¬ 
bonates of calcium and magnesium, though present in small actual 


COMPOSITION OF THE OIL-FIELD WATERS. 


61 


amount, constitute an unusually high percentage of the total solids. 
The alkalies are exceptionally low, though chloride predominates 
over sulphate. No. 21 is somewhat similar in character to the last. 
In the locality from which this water was obtained the oil measures 
are only 650 feet below the surface and the water 304 feet. The 
water is essentially a shallow type and yet has undergone some 
alteration, as evidenced by the higher ratio of carbonate to sulphate 
and by the presence of hydrogen sulphide. No. 20 is somewhat 
similar to No. 21 but more nearly resembles the types represented 
by the preceding analyses. Analyses 22 and 24 represent very 
similar top waters, both being pronounced secondary saline types. 
No. 23 is a water characterized by a small percentage of primary 
alkalinity, but it is included here because of its very low carbonate- 
sulphate ratio and its very high sulphate salinity ratio. 

Analysis 25 represents a water encountered at a depth of 670 feet 
in Midway Valley. This water is very similar in composition to No. 
87, discussed above, and represents as near an approach to normal 
connate water as can be expected. Its reactive properties resemble 
those of sea water (see analysis 52, Table 8, p. 73), though the 
secondary salinity is rather low. The sulphate salinity ratio is about 
that of sea water and therefore much lower than in the shallow 
meteoric types. The. carbonate-sulphate ratio is about normal for 
either the meteoric or the connate type. The concentration is almost 
three-fourths that of sea water. It is noteworthy that this water 
occurs in that part of the McKittrick formation correlated with the 
Tulare formation, which consists of deposits laid down in fresh water 
and which probably has never been submerged beneath the sea. 
Assuming that the sample was correctly taken, this water therefore 
presumably represents sea water that was originally entrapped in 
the marine strata below, and that has since migrated to the higher 
beds. Such an ascent would indicate considerable artesian pressure 
and would imply that the escape of the deeper waters by migration 
along the lines of stratification is practically cut off. If this explana¬ 
tion is correct it throws light on the completeness with which the 
connate water is trapped in the Midway syncline. 

Analysis 26 represents sulphur water from a well drilled near the 
outcrop of the oil measures which probably penetrates the shale of 
the Monterey group. The presence of hydrogen sulphide and also 
the somewhat high carbonate-sulphate ratio indicate that this water 
has been slightly modified, but it is included here because of its 
secondary salinity. Owing to the proximity of the outcrop of the 
sand there has been a considerable admixture of meteoric (sulphate) 
water, and chloride is not so high as in the waters farther east. 
Several other wells drilled in the brown shale just west of the western 
edge of the Midway field have obtained similar sulphur water, but, 


62 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


as already explained (p. 46), the presence of small amounts of oil or 
gas in this formation may lead to the development of a modified type 
of water some distance stratigraphically below the oil measures. 

Table 3. —Analyses of normal ground water (“top water ’ ’) from oil wells in the Coalinga 

oil field, Cal. 



15 

16 

17 

18 

19 

20 

21 

PROPERTIES OF REACTION IN PER CENT. 








Primary salinity. 

74.2 

85.4 

82.4 

82.4 

11 

66 

35.6 

Secondary salinity. 

14.6 

6.6 

0 

9.4 

51 

30 

39.0 

Primary alkalinity. 

0 

0 

12.0 

0 

0 

0 

0 

Secondary alkalinity. 

11.2 

8.0 

5.6 

8.2 

38 

4 

25.4 

Per cent of rS0 4 in rS0 4 +rCl. 

86.9 

95.0 

95.4 

95.0 

38.7 

70 

78.5 

Ratio of rC0 3 +rHC0 3 to rS0 4 . 

.15 

.09 

.22 

.09 

1.58 

.06 

.43 

CONSTITUENTS IN PARTS PER MILLION. 








Sodium (Na)o and potassium (K).... 

596 

1,111 

1,760 

3,285 

40 

641 

521 

Calcium (Ca). 

163 

83 

22 

385 

105 

209 

265 

Magnesium (Mg). 

9 

51 

42 

142 

107 

47 

336 

Iron oxide (Fe 2 0 3 ) and alumina (A1 2 0 3 ) 

102 

27 

62 

1 


6 

0 

Sulphate (S0 4 ). 

1,276 

2,376 

3,058 

7,264 

185 

1,365 

1,789 

Chloride (Cl). 

140 

91 

109 

296 

212 

427 

360 

Carbonate (C0 3 ). 

t> 117 

b 135 

b 427 

b 419 

0 

b 49 

b 484 

Bicarbonate (HC0 3 ). 





364 



Silica (Si0 2 ). 

3 

441 

6.7 

49 

• 

29 

7 

40 


2,406 

4,315 

5,486.7 

11,841 

857 

2,751 

3,795 

Hydrogen sulphide (H 2 S). 

14 


.0 

Present. 


.0 

Present. 









REACTING VALUES, IN PER CENT. 








Alkalies: 








Sodium (rNa)a. 

37.1 

42.7 

47.2 

'41.2 


/ 33.0 

17.8 

Potassium (rK). 





> 5.5 

\ 


Alkaline earths: 








Calcium (rCa). 

11.8 

3.6 

.7 

5.5 

16.5 

12.4 

10.5 

Magnesium (rMg). 

1.1 

3.7 

2.1 

3.3 

28 

4.6 

21.7 

Strong acids: 








Sulphate (rS0 4 ). 

38.6 

43.7 

39.3 

43.5 

12 

33.7 

29.3 

Chloride (rCl). 

5.8 

2.3 

1.9 

2.4 

19 

14.3 

8.0 

Weak acids: •" 








Carbonate (rC0 3 ). 

b 5.6 

b 4.0 

b 8.8 

b 4.1 

0 

b 2.0 

b 12. ' 

Bicarbonate (rHC0 3 ). 





19 











ANALYSIS AS REPORTED. C 








Sodium sulphate. 

88.82 

187. 46 

258 46 

557 32 


65 54 

42 05 

Sodium chloride. 

13.47 

8 75 

10 49 

28.57 


41.18 

34 72 

Sodium carbonate. 

.46 

1.55 

34.33 


7 16 

Calcium sulphate. 

20.19 

7.42 


28 33 


41.41 

10 40 

Calcium carbonate. 

8.96 

6.63 

3.23 

35.39 


31 09 

Magnesium sulphate. 

.35 

8.64 

4 98 

34 66 


7 83 

86 12 

Magnesium carbonate. 

1.65 

4. 29 

5 05 

4 56 


4 06 

7 82 

Iron oxide and alumina. 

5.97 

1 59 

3 64 

06 


35 

on 

Silica. 

.19 

25. 78 

.39 

2.86 


.38 

2.34 




140.06 

252.11 

320.57 

691. 75 


160. 75 

221. 70 

Hydrogen sulphide. 

.82 


.00 

Present. 


.00 

Present. 






a Reported and calculated as sodium but includes potassium. 
b Reported and calculated as carbonate but probably in part bicarbonate, 
c In hypothetic combinations, in grains per U. S. gallon. 

15. California Oilfields (Ltd.) well 2, sec. 10, T. 19 S., R. 15 E. Analyst, Smith, Emery & Co., October, 

1915. Authority, California Oilfields (Ltd.). ’ ’ 

16. California Oilfields (Ltd.) well 16, sec. 14, T. 19 S., R. 15 E. Analyst, Smith, Emery & Co., Sep¬ 

tember, 1915. Authority, California Oilfields (Ltd.). 

17. Record Oil Co. well 5, sec. 22, T. 19 S., R. 15 E. Water from above oil zone. Analyst, Smith 

Emery & Co., October, 1915. 

18. Premier Oil Co. well 3, sec. 24, T. 20 S., R. 14 E. Black sulphur water from about 700 feet, or 

about 400 feet above the oil. Analyst, Schalk Chemical Co. Authority, Premier Oil Co. 

19. Kern Trading & Oil Co. well in sec. 13, T. 20 S., R. 14 E. Sampled by G. S. Rogers, October, 

1915. Analyst, S. C. Dmsmore. b ’ * 

20. Nevada Petroleum Co. well 3, sec. 30, T. 20 S., R. 15 E. Flowing water from about 2,100 feet, or 

about 500 feet above the oil. Analyst, Dodge Manfacturing Co., March, 1911. Authority, Nevada 
Petroleum Co. 

21. Ozark Oil Co. well 3, sec. 26, T. 20 S., R. 14 E. Sulphur water from 304 feet, or about 350 feet 

above oil. Analyst, Smith, Emery & Co., January, 1912. Authority, Ozark Oil Co. 



























































































COMPOSITION OF THE OIL-FIELD WATERS. 63 

Table 4. —Analyses of normal ground water (“top water 1 ') from wells in the Coalinga 

and Midway oil fields , Cal. 


22 


23 


24 


25 


26 


PROPERTIES OF REACTION IN PER CENT. 


Primary salinity.. 

Secondary salinity.. 

Primary alkalinity.. 

Secondary alkalinity.. 

Per cent of rS0 4 in rS0 4 +rCl. 

Ratio of rCC> 3 +rHC 03 to rS 0 4 . 

CONSTITUENTS IN PARTS PER MILLION. 


59.2 

28.4 
0 

12.4 


77.7 

.18 


92.4 

0 

2.0 

5.6 


92.4 

.09 


53.8 

35.6 
0 

10.6 


78.3 

.15 


94.0 

5.4 

0 

.6 


7.0 

.08 


90.2 

3.4 
0 

6.4 


30.6 

.22 


Sodium (Na). 

Potassium (K).. 

Calcium (Ca). 

Magnesium (Mg). 

Iron oxide (Fe 2 0 3 ) and alumina (Al 2 O a ) 

Sulphate (S0 4 ). 

Chloride (Cl). 

Carbonate (CO 3 ). 

Bicarbonate (HCO3). 

Silica (Si0 2 ). 


a 442 


al,335 


a 661 


08 ,794 


140 
76 
6 39 
1,062 
226 
6 121 


34 

22 


2,518 
154 
b 141 


249 
148 
6 105 
1,793 
368 
6 169 


397 

61 

6 2.4 
1,381 
13,304 
6 71 


17 


45 


911 

8.4 

23 

39 


605 

1,013 

0 

175 

32 


Hydrogen sulphide (H 2 S). 

REACTING VALUES IN PER CENT. 


Alkalies: 

Sodium (rNa). 

Potassium (rK). 

Alkaline earths: 

Calcium (rCa). 

Magnesium (rMg). 

Strong acids: 

Sulphate (rS0 4 ). 

Chloride (rCl). 

Weak acids: 

Carbonate (rCOs). 

Bicarbonate (rHCC> 3 ). 

ANALYSIS AS REPORTED. C 


2,106 


o29.6 

10.7 

9.7 

34.0 

9.8 

6 6.2 


4,221 


o47.2 

1.4 

1.4 

42.7 

3.5 

6 3.8 


3,493 


o26.9 

11.6 

11.5 

35.0 

9.7 

6 5.3 


24,055.4 


o 47.0 

2.4 

.6 

3.5 
46.2 

6.3 


2,717.4 

Present 


44.7 

.4 

1.3 

3.6 

14 

32 

.0 

3.2 


Sodium sulphate. 
Sodium chloride.. 
Sodium carbonate 


53.33 

21.74 


217.70 
14.83 
3.59 


76.10 25.95 

35.46 1,282.50 


Calcium sulphate. 

Calcium carbonate. 

Magnesium sulphate.... 
Magnesium carbonate.., 
Iron oxide and alumina 


14.84 . 

9.47 5.00 

19.44 . 

1.92 4.48 

2.27 . 


Silica 


.98 


33.01 

12.07 

37.62 


69.42 

6.92 

17.75 


3.67 . 

6.12 .14 

. 2.65 


123.01 


246.58 


204.05 


1,405.33 


a Reported and calculated as sodium but includes potassium. 

6 Reported and calculated as carbonate but probably in part bicarbonate, 
c In hypothetic combinations, in grains per U. S. gallon. 

Coalinga field: 

22, 23, and 24. Kern Trading & Oil Co. wells in sec. 25, T. 20 S., R. 14 E. Nos. 22 and 23 represent 
water which corroded the casing and temporarily flooded the wells. The water certainly occurs 
above the oil and probably more than 500 feet above it. No. 24 represents water from a depth 
of 648 feet, or just above the zone of tar sands and 480 feet above the oil. Analyst, Kern Trading 
& Oil Co. 

Midway field: 

25. Standard Oil Co. well 6, sec. 12, T. 32 S., R. 23 E. Water is from 670 to 730 feet, or about 2,000 

feet above the horizon of the oil. Analyst, Standard Oil Co. January, 1912. 

26. August Water Co., California Amalgamated well 2, sec. 35, T. 32 S., R. 23 E. Sulphur water from 

1,090 feet, probably in shale of Monterey group. Temperature, 84° F. (See p. 19.) Sampled 
by G. S. Rogers, July, 1914. Analyst, Chase Palmer. 


I 

















































































64 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

MODIFIED GROUND WATER. 

Table 5 contains analyses of water, modified presumably by the 
action of the hydrocarbons, from the Coalinga, Midway, and Sunset 
fields. As already explained, the modified group is arbitrarily 
assumed to include only those waters that are primary alkaline in 
character and that contain a moderate to high proportion of sulphate. 
In all the analyses included in Table 5 the ratio of carbonate to sul¬ 
phate is greater than 1, and in several it is much higher. Most of 
these waters are characterized by a high percentage of primary 
alkalinity, but this figure is largely governed by the concentration 
of the chloride. 

Analysis 27 represents the type of water ttiat occurs in the Eastside 
Coalinga field some distance above the oil. It will be noted that the 
primary salinity is very low and primary alkalinity very high. The 
sulphate salinity ratio is fairly high, but this is due chiefly to the very 
small proportion of chloride present. When chloride is as low as it 
is in most of the waters from this district the relative proportions of 
sulphate and chloride are of less value than the comparison of sul¬ 
phate and carbonate. Analysis 28 shows a somewhat saltier water 
from the north end of the Coalinga syncline. The primary alkalinity 
is fairly high though the water still contains a large amount of sul¬ 
phate. No. 29 is a good analysis of the distinctly modified water 
that occurs just above the tar sand zone in the Westside Coalinga 
field. Despite the high sulphate salinity ratio and the low carbonate- 
sulphate ratio the fact that some of the sulphate has already been 
reduced is indicated by the presence of a considerable amount of 
sulphide, part of which is combined as hydrogen sulphide. Analysis 
30 represents the water used at the Coalinga Sulphur Baths, which 
is interesting because, although distinctly a modified type, it occurs 
600 feet below the oil. This water, however, is probably obtained 
from the Chico strata (Upper Cretaceous*) and is very different from 
that obtained in or just below the oil zone (upper Miocene), which 
is represented by analysis 64 (Table 10, p. 76). 

Analysis 31 probably represents a mixture of waters above and 
below the oil from a well on the extreme western edge of the Midway 
field. The sulphate is high in proportion to both chloride and 
carbonate, indicating a considerable admixture of upper water. It 
is also possible, because of the proximity of the outcrop of the sands 
and the fact that large quantities of water are being removed from 
them, that sulphate water is entering at the outcrop of the lower water 
sand faster than it is being altered. Analysis 32 represents an 
unusual type of water from Buena Vista Valley. Although occurring 


1 Arnold, Ralph, and Anderson, Robert, Geology and oil resources of the Coalinga district, Cal.: U. S. 
Geol. Survey Bull. 398, p. 223, 1910. 



COMPOSITION OF THE OIL-FIELD WATERS. 


65 


at a depth of about 3,000 feet its concentration is only 364 parts, 
which is less than that of even the shallowest ground water in most 
localities in the fields of the west side. No oil had been encountered 
at this depth, and if present is probably some distance below. The 
low carbonate-sulphate ratio shown by the analysis indicates a water 
only slightly modified, if at all, though as no shallower water from this 
locality is available for comparison a definite estimate of its relations 
can not be made. No. 33 is a much saltier and more concentrated 
water than any of the foregoing and is included here for purposes of 
comparison. This water has been greatly modified and closely 
approaches the altered water associated with the oil along the western 
edge of the Midway and Sunset fields. (See Table 11, p. 77.) The 
presence of hydrogen sulphide and the appreciable amount of sulphate 
still retained prevent its classification as an altered water, especially 
as it occurs at least a hundred feet above the oil. A similar type is 
shown by analysis 81 (Table 13, p. 83). 

Analysis 80 (Table 12, p. 81) represents a meteoric water of the 
modified type similar in every way to those discussed above but 
formed under very different conditions. This water is the mine water 
at the old coal mine in sec. 26, T. 30 S., R. 14 E. It probably has 
not been affected by oil or gas and its modification must therefore 
be due to the coal. 

60439°—Bull. 653—17-5 

/ 



66 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


Table 5. —Analyses of ground water modified by action of oil, from wells in the Coalinga, 
, Midway, and Sunset oil fields, Cal . 


27 

28 

29 

30 

31 

32 

33 

14.0 

49.0 

45.4 

20.2 

44.6 

56.6 

77.4 

0 

0 

0 

0 

0 

0 

0 

82.6 

47.4 

22.4 

74.2 

39.0 

11.0 

15.6 

3.4 

3.6 

32.2 

5.6 

16.4 

32.4 

7.0 

75.7 

43.7 

67.4 

25.7 

58.3 

64.0 

1.2 

7.5 

2.4 

1.6 

15.3 

2.1 

1.2 

22.6 

a 1,003 

t 

a 807 

705 

460 

618 

a 93 

4,969 



21 

10 

33 


102 

17 

26 

124 

19 

31 

26 

109 

9 


104 

2.6 

45 

8 

144 

1 64.8 


f Trace. 

Trace. 

Trace. 

1 6 4.8 


/ 


\. 


3.1 

/ 


231 

377 

679 

53 

403 

103 

109 

54 

354 

241 

113 

210 

43 

6, 740 

cl,067 

c 555 

0 

0 

160 

c 77 

0 



1,366 

1,037 

693 


3,623 

52 


45 





60 


97 

34 

115 

9.6 

67 

2,497.8 

2,119 

2,690 

1,202.6 

1,959.1 

364.4 

14,025 



27 

2 



1.3 








a 48.3 

o48.2 

33.3 

47.1 

40.5 

o33.8 

46.0 



.6 

.1 

1.3 


.5 

.9 

1.8 

6.8 

2.3 

2.4 

10.7 

1.1 

.8 


9.3 

.5 

5.8 

5.5 

2.4 

5.3 

10.7 

15.3 

2.6 

13.0 

18.1 

.5 

1.7 

13.8 

7.4 

7.5 

9.3 

10.2 

38.2 

c39.5 

c 25.5 

0 

0 

8.3 

c 21. 7 

0 



24.3 

39.9 

19.4 


11. 3 



3.0 












18.41 

32.60 




8.91 


5.25 

34.14 




4.17 


106. 45 

53.40 




2.03 


7.34 







1.00 







1.80 

3. 74 




3.74 


.39 






1.48 

Trace. 




1.59 


.28 





.28 


3.49 





.56 









145.89 

123.88 




21.28 










PROPERTIES OF REACTION IN PER CENT. 


Primary salinity. 

Secondary salinity... 
Primary alkalinity.. 
Secondary alkalinity. 


Ratio of rSC >4 to rSCL+rCl. 

Ratio ofrC0 3 +rHC0 3 to rSC> 4 . 


CONSTITUENTS IN PARTS PER MILLION. 

Sodium (Na). 

Potassium (K). 

Calcium (Ca). 

Magnesium (Mg). 

Iron (Fe). 

Aluminum (Al). 

Sulphate (SO 4 ). 

Chloride (Cl). 

Carbonate (C0 3 ). 

Bicarbonate (HC0 3 ). 

Sulphide (S). 

Silica (SiC> 2 ). 


Hydrogen sulphide (H 2 S). 


REACTING VALUES IN PER CENT. 
Alkalies: 

Sodium (rNa). 

Potassium (rK). 

Alkaline earths: 

Calcium (rCa).1. 

Magnesium (rMg). 

Strong acids: 

Sulphate (rSOJ. 

Chloride (rCl). 

Weak acids: 

Carbonate (rC0 3 ). 

Bicarbonate (rHC0 3 ). 

Sulphide (rS). 


ANALYSIS AS REPORTED .d 

Sodium sulphate. 

Sodium chloride. 

Sodium carbonate. 

Sodium sulphide. 

Calcium sulphate. 

Calcium carbonate. 

Magnesium sulphate. 

Magnesium carbonate. 

Iron and alumina. 

Silica. 


0 Reported and calculated as sodium but includes potassium. 

& Fe 20 3 +Al 2 0 3 . 

c Reported and calculated as carbonate but probably in part bicarbonate. 
d In hypothetic combinations, in grains per U. S. gallon. 


Coalinga field: 

27. California Oilfields (Ltd.) well 16, sec. 26, T. 19 S., R. 15 E. Waterf rom 2,415 to 2,450 feet (above the 

oil). Analyst, Smith, Emery & Co., November, 1915. Authority, California Oilfields (Ltd.). 

28. Union Oil Co. well La Vista 4, sec. 4, T. 20 S., R. 15 E. Water from 3,191 feet, or about 400 feet 

above first show of oil reported. Analyst, E. H. Miller, April, 1911. Authority, Union Oil Co. 

29. Coalinga Homestake water well, sec. 26, T. 20 S., R. 14 E. Sulphur water from 336 to 354 feet, 

or at top of tar sand zone and 200 to 300 feet above the oil. Sampled by G. S. Rogers, October, 
1915. Analyst, S. C. Dinsmore. 

30. Santa Rosa Oil & Development Co. water well, sec. 12, T. 21 S.. R. 14 E. Sulphur water from 

2,077 feet, or about 600 feet below the oil. Temperature, 118* F. Sampled by G. S. Rogers. 
October, 1915. Analyst, S. C. Dinsmore. ^ * 6 ’ 

Midway and Sunset fields: 

31. Stratton Water Co. well 3, sec. 7, T. 32 S., R. 23 E. Probably a mixture of waters from above 

and below the oil. Temperature, 90° F. Sampled by G. S. Rogers, August, 1914. Analyst. 
S. C. Dinsmore. 

32. Midway Basin Oil Co. well in sec. 28, T. 31S., R. 24 E. Water from 2,980 feet. No oil encountered 

though possibly present at greater depth. Analyst, Standard Oil Co., November, 1910 

33. Union Oil Co. water well Diamond 2, sec. 13, T. 11 N., R. 24 W. Sulphur water from about 650 

feet, or about 100 feet above the oil. Sampled by G. S. Rogers, September, 1915, Analyst, S C 
Dinsmore. * ’ 













































































































COMPOSITION OF THE OIL-FIELD WATERS. 


67 


ALTERED GROUND WATER. 

Reversed type .—When a pure sulphate water is altered by the 
action of hydrocarbons it apparently becomes a pure carbonate 
water, a reversal from complete salinity to complete alkalinity 
taking place. However, there are few waters anywhere that do not 
contain some chloride, and in oil fields, where the underground cir¬ 
culation is normally restricted, a large concentration of chloride is 
generally found. It is probable therefore that oil-field waters of the 
reversed type, in which chloride is practically lacking, are rare, and 
so far as the writer knows the only fields in which they constitute 
the rule rather than the exception are the Eastside Coalinga and possi¬ 
bly the Kern River fields. (See p. 85.) Tables 6 and 7 show analyses 
of this type of water. The type is characterized by low primary 
salinity and high primary alkalinity, by a moderately low con¬ 
centration, and by a high ratio of carbonate to sulphate. Owing to 
the small amount of chloride present the sulphate salinity ratio 
(per cent of rS0 4 in rS0 4 -t-rCl) is much higher than in most altered 
waters, though generally below 10. per cent. In some waters, how¬ 
ever, the actual amount of sulphate seems to be abnormally large 
for a water associated with the oil, and it is possible that in some 
localities sulphate water is entering at the outcrop and percolating 
down faster than it is being altered. 

All the analyses in Table 6 and four of those in Table 7 represent 
water from the Coalinga field. No. 34 is a sulphur water which 
occurs a short distance above the oil measures at the upper end of 
the Coalinga syncline. Circulation is doubtless restricted in this 
locality and a considerable proportion of chloride has been retained. 
The primary salinity is 35 per cent and the primary alkalinity only 
52 per cent, and the water is therefore a mixed type, approaching 
that shown in Table 10, but characterized by a lower concentration. 
The presence of hydrogen sulphide together with a small amount of 
sulphate indicates that the alteration of this water is not entirely 
complete. Analyses 37, 38, and 39 represent waters from the 
deep territory on the east side of the Coalinga anticline near its 
southern end. These waters resemble 34 in that a considerable 
proportion of chloride is present, indicating an admixture of connate 
water. The properties of these waters are very similar, and all of 
them are characterized by a high proportion of carbonate as compared 
with either chloride or sulphate. However, a rather large amount 
of sulphate is present, especially in No. 39, which may be the normal 
condition or which may be due to an admixture of upper water in 
the samples analyzed. It may also indicate that these waters occur 
above the oil measures instead of in or below them, as generally 
believed. Analysis 42, which is very similar to these, represents 


68 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

a water definitely reported to occur at 4,022 feet, or near the base 
of the main oil measures. It will be noted that this analysis shows 
only about half as much sulphate as analyses 37, 38, and 39. 

Analyses 35, 36, and 40 contain an even lower proportion of 
chloride than analysis 42 and represent the extreme of the reversed 
type. These waters occur on the east flank of the anticline, farther 
north and in shallower territory than those discussed above. Ap¬ 
parently in this locality the connate water has been entirely drained 
away and replaced by meteoric water. In Nos. 36 and 40 primary 
salinity is only 1.4 per cent, and these waters are therefore practically 
pure solutions of sodium carbonate. No. 36 contains no sulphate 
• whatever, but a small amount of the hydrogen sulphide formed by 
the reduction of the sulphate that it formerly contained is still 
present. In Nos. 35 and 40 the sulphate seems high when com¬ 
pared with the chloride, but is negligible in comparison with the 
carbonate. Analysis 41 represents a water similar to No. 40, but 
characterized by higher salinity, both chloride and sulphate. Sul¬ 
phate is relatively high, and the presence of hydrogen sulphide pre¬ 
sumably indicates that alteration is not complete. 

Analysis 43 represents a water similar to No. 41, but occurring 
under very different conditions in the Westside Coalinga field 
This water was obtained from a well drilled to a depth of only 410 feet 
(probably in the brown shale, Oligocene ?) a mile west of the developed 
oil field. The strata dip steeply in this locality and the water sand 
outcrops not far west of the well. The occurrence of an almost 
completely altered water so close to the surface is very unusual, but 
it is known that small quantities of oil or gas are disseminated 
through the formation, and there is said to be an oil seep within a 
mile of the well. Furthermore, only a very small supply of this 
water was found and the action of reducing agents would therefore 
have been localized. Ordinarily, however, the water obtained from 
the brown shale in similar relative locations is only partly modified. 

Analyses 44 and 45 represent waters of the reversed type from the 
northern part of the Midway field. No. 44 was obtained from a 
depth of 3,860 feet or probably several thousand feet below the 
main oil measures, but it is reported that a “stray” oil sand was 
found just below the water. It is said that the production of this 
well increases perceptibly after the rains, which is not inconsistent 
with the fact that the water is chiefly of meteoric origin. No. 45 is 
a similar type of water, though it contains an even smaller propor¬ 
tion of chloride and is less concentrated. It occurs above the oil 
measures and probably in the zone of tar sands. These waters are very 
different from those found 2 miles to the southeast and described in 
the following section. 


COMPOSITION OF THE OIL-FIELD WATERS. 


69 


Analysis 85 (Table 14, p. 85) shows a similar water from the Kern 
Kiver field. It resembles the waters of the west side very closely, 
although its concentration is lower and its secondary alkalinity is 
somewhat higher. 

Table 6 . —Analysis of essentially meteoric water altered by action of oil {reversed type), 

from oil wells in the Coalinga oil fields, Cal. 


PROPERTIES OF REACTION IN PER CENT. 

Primary salinity. 

Secondary salinity. 

Primary alkalinity. 

Secondary alkalinity. 

Per cent of rS0 4 in rS0 4 +rCl. 

Ratio ofrC 03 +rHC 0 3 torS 0 4 . 

CONSTITUENTS IN PARTS PER MILLION. 

Sodium (Na) and potassium (K)a. 

Calcium (Ca). 

Magnesium (Mg). 

Iron oxide (F 6203 ) and alumina (A1 2 0 3 )... 

Sulphate (S 0 4 ). 

Chloride (Cl). 

Carbonate (CC> 3 )Z>. 

Silica (Si0 2 ). 


Hydrogen sulphide (H 2 S). 

REACTING VALUES IN PER CENT. 

Alkalies: 

Sodium (rNa) and potassium (rK)a... 
Alkaline earths: 

Calcium (rCa). 

Magnesium (rMg). 

Strong acids: 

Sulphate (rS0 4 ). 

Chloride (rCl). 

Weak acids: 

Carbonate (rCC> 3 )&. 

ANALYSIS AS REPORTED .c 

Sodium sulphate. 

Sodium chloride. 

Sodium carbonate. 

Calcium sulphate. 

Calcium chloride... 

Calcium carbonate. 

Magnesium sulphate. 

Magnesium chloride. 

Magnesium carbonate. 

Iron oxide and alumina. 

Silica. 


Hydrogen sulphide 


34 

35 

36 

37 

38 

39 

34.8 

4.6 

1.4 

28.6 

30.6 

34.4 

0 

0 

0 

0 

0 

0 

51.8 

75.8 

94.4 

69.4 

68.6 

59.2 

13.4 

19.6 

4.2 

2.0 

.8 

6.4 

2.8 

4.4 

0 

10.5 

9.2 

13.4 

65.2 

477 

00 

23.8 

24.8 

14.3 

799 

1,123 

1,458 

3,699 

3,968 

2,610 

62 

60 

22 

13 

6.3 

122 

28 

109 

22 

37 

16 

21 

15 

38 

3.4 

4.8 

1.5 


22 

8 

0 

238 

228 

262 

480 

95 

32 

1,494 

1,700 

1,280 

784 

1,737 

1,953 

3,514 

3,634 

2,382 

86 

69 

41 

53 

29 

37 

2,276 

3,239 

3,531.4 

9,052.8 

9,582.8 

6,714 

26 

0 

6.3 




43.3 

40.2 

47.9 

49.0 

49.6 

46.8 

3.8 

2.4 

.8 

.2 

.1 

2.5 

2.9 

7.4 

1.3 

.8 

.3 

.7 

.5 

. 1 

.0 

1.5 

1.4 

2.3 

16.9 

2.2 

.7 

12.8 

13.9 

14.9 

32.6 

47.7 

49.3 

35.7 

34.7 

32.8 

1.89 



20.61 

19. 68 

21.39 

46.21 


2.03 

143.97 

163.86 

123.43 

64.18 

150.95 

193.69 

351.42 

370. 29 

222.96 


.48 




.40 



.55 




9.05 

8.39 

2. 79 

1.91 

.92 

17.46 


. 15 




.73 


7.45 

.43 




5.74 

15.52 

4.07 

7.56 

3.26 

3.70 

.85 

2.22 

.19 

.28 

.09 


5.05 

4.05 

2.45 

3.07 

1.72 

2.18 

132.97 

189.21 

206. 20 

528.82 

559.82 

392.25 

1.52 

.00 

.37 





a Reported and calculated as sodium but includes potassium. 
b Reported and calculated as carbonate but probably in part bicarbonate, 
c In hypothetic combinations, in grains per U. S. gallon. 


34. California Oilfields (Ltd.) well 5, sec. 29, T. 19 S , R. 15 E. Sulphur water from 2,655 feet, or a short 

distance above oil zone. Analyst, Standard Oil Co., October, 1915. 

35. California Oilfields (Ltd.) well 37, sec. 27, T. 19S.,R. 15 E. Analyst, Smith, Emery & Co., October, 

1915. Authority, California Oilfields (Ltd.). 

36. California Oilfields (Ltd.) well 15, sec. 34, T. 19S.,R.15E. Analyst, Smith, Emery & Co., November, 

1915. Authority, California Oilfields (Ltd.). 

37,38,39. Water from oil wells in secs. 35 and 36, T. 19 S., R. 15 E., and sec. 2 , T. 20 S., R. 15 E., respectively. 
This water is thought by most of the operators to occur at the base of the main oil zone; it is cer¬ 
tainly closely associated with the oil. Analyst, Kern Trading & Oil Co. 











































































70 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


Table 7. —Analyses of essentially meteoric water altered by action of oil (reversed type), 
from wells in the Coalinga and Midway oil fields, Cal., 


PROPERTIES OF REACTION IN PER CENT. 

Primary sal inity. 

Secondary salinity.. 

Primary alkalinity. 

Secondary alkalinity. 


Per cent of rSC>4 in rSCL-t-rCl.. 
Ratio of rC 03 +rHC 03 torS 04 . 


CONSTITUENTS IN PARTS PER MILLION. 


Sodium (Na). 

Potassium (K). 

Calcium (Ca). 

Magnesium (Mg).... 

Iron (Fe). 

Aluminum (Al). 

Sulphate (SO*). 

Chloride (Cl). 

Carbonate (CO3).... 
Bicarbonate (HCO3). 
Silica (SiC> 2 ). 


Hydrogen sulphide (II 2 S). 


REACTING VALUES IN PER CENT. 
Alkalies: 

Sodium (rNa). 

Potassium (rK)./.. 

Alkaline earths: 

Calcium (rCa). 

Magnesium (rMg). 

Strong acids: 

Sulphate (rSOJ. 

Chloride (rCl). 

Weak acids: 

Carbonate (rCC> 3 ). 

Bicarbonate (rHCOs). 


ANALYSIS AS REPORTED .d 


Sodium sulphate. 

Sodium chloride. 

Sodium carbonate.. 

Calcium sulphate.. 

Calcium carbonate. 

Magnesium sulphate_ 

Magnesium chloride. 

Magnesium carbonate... 
Iron oxide and alumina. 
Silica. 


Hydrogen sulphide. 


40 


1.4 

0 

88.4 

10.2 


11.4 

493 


al, 087 


25 
50 

} 63.9 

4.1 
22 
cl, 555 


41 


14.4 

0 

83.6 

2.0 


36.0 

16.5 


al,007 


10 

6.3 

61.7 


68 


2,815 

14 


111 
147 
cl, 148 


19 


a44.9 


1.2 

3.9 

.1 

.6 

c 49.3 


.98 
145.25 
.34 
3.41 
.02 
.92 
9.28 
.23 
3.97 


164.40 

.80 


2,450 
5 


42 


33.8 

0 

64.2 

2.0 


43 


27.8 
0 

69.8 
2.4 


44 


5.3 

36.8 


3,295 

23 

31 

19 

Trace. 


135 

1,695 

36 

5,956 

46 


8,214 


a 49.0 


.5 

.5 

2.6 

4.6 

C42.8 


9.57 
14.17 
115.38 
Trace. 
1.46 


1.28 

.10 

1.13 


143.09 

.29 


48.8 

.2 

.5 

.5 

.9 

16.0 

.4 

32.7 


1.4 

180 


o718 


7.2 

5 


5.8 

310 

c691 


10 


1,747 


o48.8 


.6 

.6 

.2 

13.7 

c36.1 


40.2 

0 

57.8 

2.0 


1.5 

99 


2,052 

9.7 

19 

11 

Trace. 
3.1 
28 
1,293 
342 
2,732 
72 


5,175.8 


.50 
29.93 
69.04 


1.04 


1.01 

”.*59 


102.11 


48.9 

.1 

.5 

.5 

.3 

19.8 

6.2 

23.7 


45 


22.4 
0 

60.4 
17.2 


Trace. 


o1,010 


56 

77 


Trace. 
421 
c 1,236 


Trace. 


2,800 

Present. 


o41.4 


2.6 

6.C 


11.2 

c38.8 


a Reported and calculated as sodium but includes potassium. 

6 F62O3-I-AI2O3. 

c Reported and calculated as carbonate but probably in part bicarbonate, 
o In hypothetic combinations, in grains per U. S. gallon. 

Coalinga field: 

40. California Oilfields (Ltd.) well 1, sec. 34, T. 19 S R. 15 E. Analyst, Smith, Emery & Co., Novem¬ 
ber, 1915. Authority, California Oilfields (Ltd.). ’ 

4L (Ltd.) well 31, sec 34 T. 19 S., R. 15 E. Water from about 2,156 feet, or a 

C^Iiforaia^Oflfield^(Ltd 1 ) 10llzone * Anal >’ st > Smith > Emery & Co., November, 1915. Authority, 

42. Kern Trading & Oil Co. well, in sec. 11, T. 20 S., R. 15 E. Water from 4,022 feet or near base of 
ao lowe r oil zone ® ara P led b y G - s -Rogers, October, 1915. Analyst, S. C. Dinsmore 

43. Kern Trading & Oil Co. water well 1, sec. 15, T. 20 S., R. 14 E. Water from 410 feet Well is 

Amiyst^Kern^radhig 1 ^ ^ 1 ^ ocene ^) and is located close to the outcrop of the water sand. 
Midway field: ’ 

44. G ^ water ^ ; sec ; T- 31 S -> R. 22 E. Water from brown shale 

?H’p° p Probably over 3,000 feet below horizon of main oil zone. Temperature, 

„ 434 Analyst, S.C. Dinsmore. 

P and ^ T - 1 31 ?•’ P- 22 E. Water from about 500 feet, or in tar sand zone 

cm Co° t0 300 fe6t ab e the 0ll> An alyst, Smith, Emery & Co., May, 1915. Authority, Potter 









































































































COMPOSITION OF THE OIL-FIELD WATERS. 


71 


Brine .—In Tables 8 and 9 are shown analyses of brine, or connate 
water, altered presumably by the action of hydrocarbons. For 
convenience in discussion the term brine is here restricted to waters 
that are practically sulphate-free and that are characterized by 
secondary salinity. The primary salinity generally ranges upward 
from about 80 per cent and the secondary salinity downward from 
about 20 per cent; the concentration is generally between 25,000 and 
45,000 parts per million, and secondary alkalinity is therefore very 
low. The greatest actual amount of sulphate in any of the waters 
shown is 34 parts per million, and owing to the large amounts of 
chloride present the sulphate salinity ratio is less than 0.5 per cent. 
Owing to the very small amount of both carbonate and sulphate the 
ratio between them generally has little significance. To facilitate 
comparison an analysis of ocean water is included in Table 8 as No. 52. 

Analysis 46 represents a very exceptional water from the Coalinga 
field, which is exactly on the dividing line and exhibits neither 
secondary salinity nor primary alkalinity. Carbonate is low and 
only a trace of sulphate is reported, so that this water is essentially 
a solution of sodium chloride. The concentration is unusually low 
and secondary alkalinity is present in corresponding high proportion. 
A partial analysis of a deeper water from the same well showed more 
chloride and less carbonate, indicating a true (secondary saline) 
brine. Both these waters are said to be from the brown shale below 
the oil measures. Apparently no brines have been encountered in 
the main Coalinga field south of this well, though they probably 
exist in the deeper unexplored portion of the syncline. 

The remaining analyses in Table 8 represent brines from the 
Midway syncline and the Buena Vista anticline. All these waters 
occur close to the oil, some a short distance above and others below. 
In all of them the sulphate salinity ratio is less than 0.1 per cent and 
two of them contain no sulphate whatsoever. In all other respects 
they closely resemble sea water, the properties of reaction varying 
within the limits stated above and the concentration ranging between 
29,000 and 39,000 parts. No. 48 is the only oil-field water that has 
come to the writer’s attention in which secondary salinity is as high 
as it is in sea water. 

Table 9 contains analyses of seven brines from the Midway and 
Sunset fields. Nos. 53 and 55 to 58 are in every way similar to those 
already described and are believed to be representative of the water 
associated with the oil in the central and eastern parts of these fields. 
Nos. 54 and 59 are somewhat different types, having a very much 
lower concentration than the rest. No. 54 contains an exceptionally 
high proportion of the calcium and carbonate radicles and primary 
and secondary salinity are therefore unusually low. No. 59, which is 


t 


72 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


a water from a considerable depth, probably in the Vaqueros forma¬ 
tion, is characterized by a lower concentration than many surface 
waters, although its properties resemble those of the other brines. 
Nos. 54 and 59 contain only minute amounts of sulphate. Analysis 
88 (Table 14) represents a brine associated with the oil in the Lost 
Hills field. 


COMPOSITION OF THE OIL-FIELD WATERS. 73 


Table 8. —Analyses of brine or connate water altered by action of oil, from oil wells in 
the Coalinga and Midway oil fields, Cal., and of ocean water. 



46 

47 

48 

49 

50 

51 

52 

PROPERTIES OF REACTION IN PER 








CENT. 








Primary salinity. 

96.2 

86.6 

75.9 

83.8 

91.8 

82.0 

78.6 

Secondary salinity. 

.0 

12.2 

22.5 

13.4 

6.6 

17.0 

21.1 

Primary alkalinity. 

0 

0 

0 

0 

0 

0 

0 

Secondary alkalinity. 

3.8 

1.2 

1.6 

2.8 

1.6 

1.0 

.3 

Per cent of rS0 4 in rS0 4 +rCl_ 

Trace. 

0 

.01 

.06 

0 

.01 

9.2 

CONSTITUENTS IN PARTS PER 








MILLION. 








Sodium (Na). 

o4,137 

11,160 

alO,522 

al3,253 

al0,704 

11,011 

10,710 

Potassium (K). 


124 




156 

390 

Calcium (Ca).. 

81 

848 

2,894 

1,089 

284 

1,188 

420 

Magnesium (Mg). 

40 

425 

7.2 

685 

326 

510 

1,300 

Iron oxide (Fe 203 ) and alumina 








(AI 2 O 3 ). 

32 


35 

11 




Sulphate (S0 4 ). 

Trace. 

0 

31 

18 

0 

9 

2,700 

Chloride (Cl). 

6,367 

20,694 

20,955 

23,553 

17,631 

18,750 

19,410 

Carbonate (C0 3 ). 

b 218 

48 

b 293 

b 626 

b 243 

0 

5 70 

Bicarbonate (HCOj). 


359 




280 


Silica (SiOA .... 

49 

102 

18 

65 

12 

123 











10,924 

33,578 

34,755.2 

39,300 

29,200 

31,885 

35,000 

REACTING VALUES IN PER CENT. 








Alkalies: 








Sodium (rNa). 

a 48.1 

43.0 

a 37.95 

o41.9 

a 45.9 

40.6 

38.5 

Potassium (rK). 


.3 




.4 

.8 

Alkaline earths: 








Calcium (rCa). 

1.0 

3.7 

12.00 

4.0 

1.4 

5.3 

1.8 

Magnesium (rMg). 

.9 

3.0 

.05 

4.1 

2.7 

3.7 

8.9 

Strong acids: 








Sulphate (rS0 4 ). 

Trace. 

.0 

.05 


.0 

Trace. 

4.6 

Chloride (rCl). 

48.1 

49.4 

49.15 

48.5 

49.2 

49.5 

45.2 

Weak acids: 








Carbonate (rC0 3 ). 

b 1.9 

.1 

b. 80 

b 1.5 

b. 8 

.0 

b. 2 

Bicarbonate (rHCOa). 


.5 




.5 










ANALYSIS AS REPORTED. C 








Sodium sulphate... 

Trace. 







Sodium chloride. 

605.36 


1,560.10 

i, 954 .36 

1,575.11 



Sodium carbonate. 

7.34 



9.53 

10.90 



Calcium sulphate. 

Trace. 


2.57 

1.47 




Calcium chloride. 

2.98 


434.50 

167. 26 

45.99 



Calcium carbonate. 

9.13 


28.50 

6.95 




Magnesium sulphate.. 

Trace. 







Magnesium chloride. 

4. 24 


1.64 

114. 05 

61.88 



Magnesium carbonate. 

4.37 



37.95 

11.24 



Iron and alumina.. 

1.88 


2.05 

.63 




Silica. 

2. 84 


1.08 

3. 83 

.70 












638.14 


2,030. 44 

2,296.03 

1,705. 82 




a Reported and calculated as sodium but includes potassium. 
b Reported and calculated as carbonate but probably in part bicarbonate. 
c In hypothetic combinations, in grains per U. S. gallon. 

Coalinga field: . 

46. Acorn Oil Co. well 1, sec. 2, T. 20 S., R. 14 E. Flowing water from 1,104 feet (in brown shale), or 

about 1,000 feet below main oil horizon. Temperature, 86 ° F. Analyst, Luckhardt & Co. 
Authority, H. W. Bell. A partial analysis by H. W. Bell of water struck in this well at 2,528 
feet shows about 7,700 parts per million of Cl and 175 parts of CO 3 . This deeper water thus 
probably resembles No. 50 in its properties of reaction. 

Midway field: 

47. Mays Consolidated Oil Co. well 6 , sec. 28, T. 31 S., R. 23 E. Flowing water from 3,000 feet, or a 

few feet beneath the oil sand. Temperature, 125° F. Sampled by G. S. Rogers, September, 
1915. Analyst, S. C. Dinsmore. 

48. Standard Oil Co. well 6 , sec. 22 , T. 31 S., R. 23 E. Water from 2,700 feet, or in oil zone. Analyst, 

Standard Oil Co., September, 1915. 

49. Associated Oil Co. well 2, sec. 32, T. 31 S., R. 23 E. Water from a short distance above 3,100 feet, 

or more than 100 feet above the oil. Analyst, Smith, Emery & Co. Authority, Associated Oil Co. 

50. Associated Oil Co. well Pioneer Midway 7, sec. 30, T. 31 S., R. 23 E. Water probably from 2,840 

to 2,885 feet, or in the oil measures. Analyst, Smith, Emery & Co. Authority, Associated Oil Co. 

51. Honolulu Oil Co. well 6 , sec. 10, T. 32 S., R. 24 E. Water from 2,755 feet, or close to the horizon. 

of the oil. Sampled by Paul Paine. Analyst, S. C. Dinsmore. 

Ocean water: 

52. Interpretation of the mean of 77 analyses by W. Dittmar of sea water collected by the Challenger 

expedition (Challenger Exped. Rept., Physics and chemistry, vol. 1, p. 203, 1884). 





































































































74 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


Table 9 . —Analyses of brine or connate water altered by the action of the oil, from oil wells 

in the Midway and Sunset oil fields, Cal. 



53 

54 

55 

56 

57 

58 

59 

PROPERTIES OF REACTION IN 








PER CENT. 








Primary salinity... 

84.2 

48.6 

84.0 

84.6 

83.4 

83.6 

85.0 

Secondary salinity. 

14.6 

5.0 

11.4 

13.8 

16.2 

16.0 

12.6 

Primary alkalinity. 

0 

0 

0 

0 

0 

0 

0 

Secondary alkalinity. 

1.2 

46.4 

4.6 

1.6 

.4 

.4 

2.4 

Per cent ofrSCMn rS 04 +rCl... 

.01 

Trace. 

0 

.20 

Trace. 

.0 

.48 

CONSTITUENTS IN PARTS PER 








MILLION. 








Sodium (Na). 

al5,015 

®1,323 

o9,855 

10,548 

ail,656 

11,176 

l A71 

Potassium (K). 




72 


86 

> 0/1 

Calcium (Ca).. 

1,895 

1,223 

1,064 

772 

1,281 

1,100 

69 

Magnesium (Mg). 

342 


345 

570 

443 

503 

21 

Iron (Fe). 

} 611 

6 1.7 . 

65 

f . 1 




Aluminum (Al). 

{ 8 .4 




Sulphate (SO 4 ).. 

32 

3.6 

0 

34 

4.3 

0 

7.8 

Nitrate (NO 3 ). 




0 


45 

0 

Chloride (Cl).. 

27,102 

2,254 

17,231 

19,624 

21,415 

20,421 

1,170 

Iodide (I). 






29 


Carbonate (CO 3 ). 

c 275 

cl, 645 

c692 

0 

c 90 

0 

0 

Bicarbonate (HCO 3 ). 




573 


162 

48 

Silica (SiC> 2 ). 

60 

4.1 

10 

43 

39 


5 









44,732 

6,454. 4 

29,202 

31,953.5 

34,928.3 

33,440 

1,967.8 

Carbon dioxide (CO 2 ). 




Presen t 


Present. 

Present. 








REACTING VALUES IN PER CENT. 








Alkalies: 








Sodium (rNa). 

a 42.1 

a 24.3 

a 42.0 

42.1 

041.7 

41.6 


Potassium (rk). 




.2 


.2 

> 42.5 

Alkaline earths: 








Calcium (rCa). 

6.1 

25.7 

5.2 

3.5 

5.3 

4.7 

5.0 

Magnesium (rMg). 

1.8 


2.8 

4.2 

3.0 

3.5 

2.5 

Strong acids: 




Sulphate (rSO<). 




. 1 



.2 

Nitrate (rN 03 >. 






. 1 

Chloride (rCl). 

49.4 

26.8 

47.7 

49.1 

49.8 

49.7 

48.6 

Weak acids: 








Carbonate (rCOs). 

c.6 

c23.2 

c2.3 

.0 

c.2 

.0 

.0 

Bicarbonate (rHCOs). 




.8 


.2 

1.2 








ANALYSIS AS REPORTED .d 








Sodium chloride. 

2,226. 21 

196.25 

1,461.20 





Calcium sulphate. 

2.64 

.30 






Calcium chloride. 

274. 80 

19.92 

97.36 





Calcium carbonate. 

26.78 

160. 25 

67.39 





Magnesium chlorid e. 

78. 40 


78.93 





Iron oxide and alumina. 

.64 

.10 

.29 





Silica. 

3.50 

.24 

.62 














2,612.97 

377.06 

1,705. 79 






a Reported and calculated as sodium but includes potassium. 

6 F62O3+AI2O3. 

c Reported and calculated as carbonate but probably in part bicarbonate. 
d In hypothetic combinations, in grains per U. S. gallon. 

Midway field: 

53. Standard Oil Co. well 7, sec. 12, T. 32 S., R. 23 E. Water from 2,600 feet, or 400 feet below a gas 

sand and about 100 feet above the oil. Analyst, Standard Oil Co., June, 1913. 

54. Standard Oil Co. well3, sec. 20, T. 32 S., R. 24 E. Water from 3,250 feet, or about 200 feet below 

the oil. Analyst, Standard Oil Co., February, 1911. 

55. Standard Oil Co. well 1, sec. 28, T. 32 S., R. 24 E. Waterfrom 2,390feet, or about 400feet above 

the oil. Analyst, Standard Oil Co., August, 1909. 

Sunset field: 

56. M. J. & M. M. Oil Co. well M. J. 6, sec. 36, T. 12 N., R. 24 W. 

about 200 feet below top oil sand and above lower oil sand. 

1914. Analyst, S. C. Dinsmore. 

K ^ P Tl i a u i ? g < *L 0i - 1 Co - T? 11 ’ in , NE -1 sec - 31 ; T -12N., R. 23 W. Waterfrom 2,924 feet, or about 
200 feet below horizon of top oil sand. Analyst, Kern Trading & Oil Co., January, 1915. 
Midway Northern Oil Co. well 5, sec. 32, T. 12 N., R. 23 W. Flowing water from 2,505 feet, or 
below top oil sand and about 100 feet above second oil sand. Temperature, 115° F. Sampled 
by G. S. Rogers, August, 1914. Analyst, Chase Palmer. 

Sunset Security Oil Co. well 1, sec. 29, T. 11 N., R. 23 W. Flowing water, probably from sands 
between 2,992 and 3,997 feet, or below several shows of oil. Sampled by G. S. Rogers, September, 

1915. Analyst, S. C. Dinsmore. * 


Flowing water from 2,270 feet, or 
Sampled by G. S. Rogers, July, 


57. 

58. 


59 . 























































































COMPOSITION OF THE OIL-FIELD WATERS. 


75 


Mixed type .—In Tables 10 and 11 are shown analyses of waters of 
mixed meteoric and connate origin, altered presumably by the action 
of hydrocarbons. This type naturally overlaps on the two preceding, 
for few waters can be considered wholly meteoric or wholly connate, 
but it appears to have a fairly definite geographic distribution. (See 
p. 88.) The type may be defined as comprising primary alkaline 
waters that are characterized by less than 50 per cent of primary 
alkalinity and that contain practically no sulphate. Primary salinity 
usually ranges between 55 and 85 per cent and secondary alkalinity 
between 1 and 10 per cent. The concentration is intermediate 
between that of the reversed type and that of the brine, but generally 
ranges between 6,000 and 12,000 parts. (See fig. 4.) 

Table 10 includes five analyses of this type of water from the West- 
side Coalinga field. In this locality the mixed type everywhere 
occurs in or below the oil measures and constitutes the bottom water, 
but so far as is known it does not occur above them. The only excep¬ 
tion to this statement is found in the water which in the deeper por¬ 
tion of the field replaces the oil in the highest oil sand, the so-called 
“upper edge water.” This is represented by analysis 62 and the 
bottom water by analyses 60, 61, 63, and 64. Two of these waters 
contain no sulphate whatever, in two others it is negligible, and in 
the other it amounts to 37 parts per million. The primary alkalinity 
ranges between 23 and 42 per cent and the other properties vary 
accordingly. The concentration ranges between 4,000 and 8,000 
parts. 

Analyses 65 to 73, Tables 10 and 11, represent waters of the mixed 
type in the Midway and Sunset fields. Generally speaking, these 
waters exhibit lower primary alkalinity and higher concentration 
than the Coalinga types; in other words, the mixture contains a 
somewhat larger proportion of connate water. In the Midway and 
Sunset fields this type of water is found both below and above the 
oil, No. 70, for example, occurring 700 feet above the main oil zone. 
The type is confined to the western edge of the fields or to the zone 
nearest the outcrop. 

In No. 73 the sulphate amounts to 27 parts per million; in the 
remainder it is either absent entirely or present in negligible amount. 
The properties of reaction and the concentration show essential regu¬ 
larity within the limits defined, although Nos. 66 and 72 show lower 
primary alkalinity and higher concentration, indicating a larger pro¬ 
portion of connate water. Analysis 82 (p. 83) shows another example 
of this type from the Midway field. 

Analysis 86 (Table 14, p. 85), represents a water of the mixed type 
encountered near the bottom of a well 5,135 feet deep in the Kern River 
field. It is similar in every way to the waters of this type from the 
fields on the west side of the valley, except that its concentration is 


76 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


somewhat lower. In parts of the McKittrick field water of the mixed 
type, whose original source is generally believed to have been below 
the oil, has flooded the oil measures. About 30 analyses of the water 
obtained from oil wells in this field have been made available for the 
writer’s study. All of them are very similar and belong to the same 
type, which is represented by analysis 89 (Table 14, p. 85). 


Table 10. —Analyses of mixed meteoric and connate water altered by action of oil, from 
oil wells in the Coalinga and Midivay oil fields, Cal. 



60 

61 

62 

63 

64 

65 

66 

PROPERTIES OF REACTION IN 








PER CENT. 








Primary salinity. 

54.8 

60.2 

74.4 

56.6 

67.6 

74.8 

83.6 

Secondary salinity. 

0 

0 

0 

0 

0 

0 

0 

Primary alkalinity. 

35.6 

36.0 

22.8 

42.2 

30.2 

24.4 

11.8 

Secondary alkalinity. 

9.6 

3.8 

2.8 

1.2 

2.2 

.8 

4.6 

Per cent of rS 04 in rS0 4 -f rCl... 

* 

0 

1.0 

0 

Trace. 

.01 

0 

.01 

CONSTITUENTS IN PARTS PER 








MILLION. 








Sodium (Na). 

Potassium (K). 

1 2,273 

/ 2,951 

1 77 

1,885 

20 

°1,749 

1 3,315 

/ 3,140 

24 

a 7,090 

Calcium (Ca).. 

77 

19 

17 

10 

19 

9.3 

73 

Magnesium (Mg). 

81 

53 

18 

6.3 

28 

3.6 

135 

Iron (Fe). 

22 

Trace. 

Trace. 

} 6 2.6 

f Trace. 


} 6 13 

Aluminum (Al). 





Sulphate (S0 4 ). 

0 

37 

0 

0.7 

. 

4.9 

0 

4.5 

Chloride (Cl). 

2,119 

2,960 

2,170 

1,543 

3,526 

3,662 

9,566 

Carbonate (Co 3 ). 

0 

192 

120 

cl, 001 

0 

'219 

c1,588 

Bicarbonate (HC0 3 ). 

3,013 

3,013 

1,049 


2,903 

1,708 


Silica (Si0 2 ). 

61 

119 

' 75 

33 

68 

40 

44 


6,116 

7,891 

4,822 

4,345. 6 

8,390.9 

7,939.9 

18,513. 5 

Carbon dioxide. 




18 



0 







REACTING VALUES IN PER CENT. 








Alkalies: 








Sodium (rNa). 


/ 47.4 

48.3 

a 49.4 


/ 49.4 

a 47.7 

Potassium (rK). 

> 45. Z 

f .7 

.3 


) 48.9 

l 2 


Alkaline earths: 








Calcium (rCa). 

1.8 

.3 

.5 

.3 

.3 

.2 

. 6 

Magnesium (rMg). 

3.0 

1.6 

.9 

.3 

.8 

.1 

1.7 

Strong acids: 








Sulphate (rS0 4 ). 

0 

.3 


Trace 


o 


Chloride (rCl). 

27.4 

29.8 

37.2 

28.3 

33.8 

37.4 

41.8 

Weak acids: 








Carbonate (rC0 3 ). 

0 

2.3 

2.4 

c 21. 7 

0 

2.6 

c 8.2 

Bicarbonate (rHC0 3 ). 

22.6 

17.6 

10.4 


16.2 

10.1 



a Reported and calculated as sodium but includes potassium. 

6 F 62 O 3 +AI 2 O 3 . 

c Reported and calculated as carbonate but probably in part bicarbonate. 

Coalinga field: 

60. Section Seven Oil Co. well 5, sec. 7, T. 20 S., R. 15 E. Sampled by S. H. Hain, October, 1915. 

Analyst, S. C. Dinsmore.. ’ 

61. American Petroleum Co. well 2 N, sec. 30, T. 20 S., R. 15 E. Water from 1,916 feet, or 3 feet below 

main oil. Sampled by T. J. Crumpton, August, 1912. Analyst, S. C. Dinsmore, November, 

iy i5» 

62. American Petroleum Co. well 21, sec. 30, T. 20 S., R. 15 E. Water from a short distance above 

the producing oil sand (“upper edge water”). Sampled by T. J. Crumpton, August, 1912 
Analyst, S. Q. Dinsmore, November, 1915. & ’ 

63. Nevada Petroleum Co. well 1 sec. 20, T. 20 S., R. 15 E. Water from 3,305 feet, or about 25 feet 

below lowest oil. Analyst, Smith, Emery & Co. Authority, Nevada Petroleum Co. 

64 ' L Q C 1 i e A’J n e L 1S d and Vfi 6 ’ TaA 1 S P 3 V 15 E - Water from sand probably in oil /.one. 
Sampled by G. S. Rogers, October, 1915. Analyst, S. C. Dinsmore. 

Midway field: 

65. Associated Oil Co. well 1, sec. 35, T. 31 S., R. 22 E. Water from 1,495 to 1,727 feet, or about 100 

lyst ^hase l'ahne ? 1 Sand ' Tem P erature > l20 ° F - Sampled by G. S. Rogers, July, 1914. Ana- 

66 . North American Oil Consolidated Co. well 71, sec. 16, T. 32 S., R. 23 E. Water probably from 

North AmeS OUfoZli&rtCo^ m * ySt ' Sm “ h ’ Emery * Co - March ’ A ^ority, 





































































COMPOSITION OF THE OIL-FIELD WATERS. 77 


Table 11. —Analyses of mixed meteoric and connate water altered by action of oil , from 

wells in the Midway and Sunset oil fields, Cal. 



67 

68 

69 

70 

71 

72 

73 

PROPERTIES OF REACTION IN 








PER CENT. 








Primary salinitv. 

64.0 

62.6 

76.0 

77.2 

69.0 

82.0 

74.2 

Secondary salinity. 

0 

0 

0 

0 

0 

0 

0 

Primary alkalinitv. 

33.2 

35.4 

20.2 

21.6 

29.2 

13.8 

23.0 

Secondary alkalinity. 

2.8 

2.0 

3.8 

1.2 

1.8 

4.2 

2.8 

Per cent of rS 04 in rS 04 +rCl... 

t 

Trace. 

.2 

.01 

.01 

.1 

Trace. 

.4 

CONSTITUENTS IN PARTS PER 








MILLION. 








Sodium (Na). 

1 Q 091 

/ 3,627 

a 3,595 

a 5,933 

4,188 

1 q Ary 7 

/ 3,649 

Potassium (K). 


30 



52 

1 4 61 

24 

Calcium (Cal.. 

37 

41 

50 

29 

31 

163 

l 

57 

Magnesium (Mg). 

41 

17 

48 

21 

21 

94 

23 

Iron (Fe). 

Trace. 

.3 

} 6 1.7 

/. 

Trace. 


.3 

Aluminum (Al). 


6. 6 


5.2 


4.5 

Sulphate (SO 4 ). 

1 

14 

3.2 

6 

11 

3 

27 

Chloride (Cl). 

3,977 

3,608 

4,370 

7,125 

4,593 

11,123 

4,364 

Carbonate (CO3). 

0 

0 

cl,172 

cl,784 

108 

0 

0 

Riearbonate CHCOO. 

3,855 

3,793 



3,477 

4,270 

2,818 

Silica (SiOj).'.!. 

136 

122 

47 

117 

125 

108 

98 


10,011 

9,333.9 

9,286.9 

15,015 

10,846.2 

22,031 

9,633.8 

REACTING VALUES IN PER CENT. 








Alkalies: 








Sodium (rNa). 

Potassium frK'l. 

) 48.6 

/ 48.8 

1 .2 

a 48.1 

0 49.4 

48.8 

.3 

} 47.9 

/ 48.4 

1 .2 

Alkaline earths: 








Calcium (rCa). 

.5 

.6 

.8 

.3 

.4 

1.1 

.8 

Magnesium (rMg). 

.9 

.4 

1.1 

.3 

.5 

1.0 

.6 

Strong acids: 








Sulphate (rSOD. 

Trace. 

.1 

Trace. 

Trace. 

.1 

Trace. 

.2 

Chloride (rCl). 

32.0 

31.2 

38.0 

38.6 

34.4 

41.0 

36.9 

Weak acids: 








Carbonate (rC 03 ). 

0 

0 

c 12.0 

c 11.4 

.9 

0 

0 

Bicarbonate (rHCOj). 

18.0 

18.7 



14.6 

9.0 

12.9 


a Reported and calculated as sodium but includes potassium. 
b F62O3+AI2O3. 

c Reported and calculated as carbonate but probably in part bicarbonate. 


Midway field: 

67. General Petroleum Co. water well 2, sec. 15, T. 32 S., R. 23 E. Water from 1,765 to 1,820 feet, or 

about 150 feet below the oil. Temperature, 102° F. Sampled by G. S. Rogers, July, 1914. 
Analyst, S. C. Dinsmore. 

68. Crescius Oil Co. water well 6, sec. 25, T. 32 S., R. 23 E. Water from 1,460 feet, or about 50 feet 

below the oil. Temperature, 97° F. Sampled by G. S. Rogers, June, 1914. Analyst, S. C. 
Dinsmore. 

69. Standard Oil Co. well 3, sec. 24, T. 32 S., R. 23 E. Water from 1,505 feet, or below tar sand and 

above oil sand. Temperature, 96° to 103° F. Analyst, Standard Oil Co., April, 1909. 

70. Standard Oil Co. well 2, sec. 14, T. 32 S., R. 23 E. Water from 2.000 feet below a show of gas but 

about 700 feet above the oil. Analyst, Standard Oil Co., July, 1909. 

71. August Water Co. well 3, sec. 31, T. 32 S., R. 24 E. Water from sands between 1,334 and 1,609 

feet, or below the oil. Temperature, 109° F. Sampled by G. S. Rogers, July, 1914. Analyst, 
S. C. Dinsmore. 

Sunset field* 

72. Sunset Monarch Oil Co. well F, sec. 26, T. 12 N., R. 24 W. Flowing water from 2,540 to 2,560 feet, 

or about 125 feet below top oil sand. Temperature, 93° F. Sampled by G. S. Rogers, July, 
1914. Analyst, S. C. Dinsmore. 

73. Good Roads Oil Co. well 14. sec. 12, T. 11 N.. R. 24 W. Flowing water from 3,550 feet, or about 

2,500 feet below the oil. Temperature. 104° F. Sampled by G. S. Rogers, July, 1914. Analyst, 
S. C. Dinsmore. 


RELATIONS OF THE TYPES. 

Reference has already been made to figure 4, in which are shown 
the broader relations of the several types of water discussed above. 
The chief factors determining the character of the oil-field waters are 
the amount of alteration by the hydrocarbons that they have under¬ 
gone and the proportions in which connate and meteoric waters have 































































78 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

entered into their composition. Broadly considered, the first factor 
is a function of the depth, hut the second depends on structural con¬ 
ditions and is therefore a function of the geographic position. In 
figure 4 these two factors can not well be distinguished, and therefore 
in the following sections several groups of analyses are presented in 
which the two lines of variation may be studied separately. 

VERTICAL RELATIONS. 

Analyses 74 to 77, Table 12, represent four waters occurring in the 
southwestern corner of the Westside Coalinga field. The samples 
were collected at different times from four wells, and are therefore 
not as satisfactory as if taken from one well. However, the four 
wells are located within 1,200 feet of a central point, and as the water 
sands appear to be persistent within this area the four waters may 
be considered as occurring in the same well. Analysis 74 represents 
water from a depth of about 800 feet, and may include some water 
from a sand at 600 feet. Analysis 75 represents a water that corroded 
the casing at 1,160 feet; its exact position is not reported in the log, 
but a study of the logs of neighboring wells reveals a persistent 
water sand which would occur in this well at about 1,100 feet, and 
which is doubtless the source of this water. Analysis 76 represents 
water from a depth of 1,347 feet, or below the tar sands and about 
250 feet above the oil, and No. 77 is the “bottom water” which occurs 
25 feet below the main oil zone. It will be noted that Nos. 74 and 

75 are secondary saline waters of the normal group, and that Nos. 

76 and 77 are primary alkaline waters. No. 76 may be referred to 
the modified group and No. 77 to the mixed type of the altered 
group. The sulphate salinity ratio decreases from 80 per cent in the 
highest water to 0.6 per cent in the lowest and the ratio of carbonate 
to sulphate increases from 0.05 in the highest to 90.5 in the lowest. 

In order to show the relations of these waters graphically the four 
analyses have been plotted in figure 5, A, as though they represented 
waters occurring in the same well. The vertical scale shows the dis¬ 
tance in feet between the water sands and the oil zone. On the hori¬ 
zontal lines representing the water sands are plotted the percentages 
of the radicles in reacting values and the concentration of the water 
in parts per 5,000, and the points thus obtained are connected by 
lines to show the variations of each constituent. A glance at the 
figure is sufficient to show that the most marked changes take place 
near the zone of tar sands or between the second and third waters; 
the two upper waters are very similar and the lowest differs from the 
third chiefly in its higher chloride. The heavy line representing 
sulphate shows the most pronounced and regular variation, decreas¬ 
ing from 38 per cent in the highest water to 0.2 per cent in the lowest. 


COMPOSITION OF THE OIL-FIELD WATERS. 


79 



Figure 5. —Variation in chemical character of waters from different depths, showing alterations by 
hydrocarbons. The horizontal lines represent the horizon of the waters and on these lines are 
plotted their analyses. (See analyses 74 to 79, Table 12.) A, Four waters from neighboring oil wells 
in sec. 36, T. 20 S., R. 14 E., Coalinga field. (Note reversal of sulphate and carbonate values as the 
oil zone is approached.) B, Two waters from a well in sec. 27, T. 18 S., R. 15 E., several miles north 
of Coalinga field. (No oil was found to a depth of more than 3,700 feet, and the waters are prol> 
ably unaffected by hydrocarbons. Note constancy of sulphate and carbonate values.) 


























































80 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


The carbonate line rises from 2 per cent in the first- water to 32 per 
cent in the third, and then, owing to the great increase of chloride in 
the bottom water, decreases to 18 per cent, although if the actual 
amount were plotted it would continue to increase. (See analyses 
74-77, Table 12.) Chloride increases only slightly down to the third 
water, but in the lowest shows a marked rise. The alkalies increase 
regularly with depth and the alkaline earths decrease. The con¬ 
centration shows a slight rise in the second water, a fall in the third, 
and a marked rise in the fourth. The lower concentration of the third 
water is presumably due to the formation of the relatively insoluble 
carbonates of the alkaline earths, which are precipitated. This also 
explains the loss of alkaline earths and the rise of alkalies in the third 
water; if actual amounts were plotted instead of percentages the 
earths would fall off even more abruptly, whereas the alkalies would 
show little increase. To sum up these variations, alkalies, chloride, 
carbonate, and the concentration value increase with depth, whereas 
alkaline earths and sulphate decrease. The most marked variations 
are exhibited by sulphate and carbonate, and although it happens 
that in this locality chloride also increases greatly in the water be¬ 
neath the oil, it may easily be shown by comparison with other areas 
that the rise in chloride is a local feature, and has no special sig¬ 
nificance. 

Analyses 78 and 79, Table 12, represent waters encountered at 
370 and 3,700 feet, respectively, in a well drilled for oil several miles 
north of the Eastside Coalinga field. No oil had been encountered 
when the lower water was reached, and it is believed that both waters 
are unaffected by hydrocarbons. These analyses may therefore be 
considered as showing the normal changes that take place with in¬ 
creasing depth. It will be noted that No. 78 is a secondary saline 
water, and that No. 79 is slightly primary alkaline owing to an 
increase in alkalies without a corresponding increase in strong acids. 
The sulphate salinity ratio in No. 78 is 80 per cent and in No. 79, 76 
per cent, and the carbonate-sulphate ratios are, respectively, 0.16 
and 0.13. 


COMPOSITION OF THE OIL-FIELD WATERS. 


81 


Table 12.— Analyses of ground water at different depths in the Coalinga oil field, Cal., 

showing alteration by oil or coal. 


[See fig. 5, p. 79.] 



74 

75 

76 

77 

78 

79 

80 

PROPERTIES OF REACTION IN 








PER CENT. 





i 



Primary salinity. 

59.0 

67.0 

36.2 

63.8 

64.6 

91.2 

21.8 

Secondary salinity. 

36.8 

18.6 

0 

0 

24.0 

0 

0 

Primary alkalinity. 

0 

0 

50.8 

30.8 

0 

6.6 

74:'4 

Secondary alkalinity. 

4.2 

14.4 

13.0 

5.4 

11.4 

2.2 

3.8 

Per cent of rS0 4 in rS0 4 +rCl... 

80.0 

67.0 

27.6 

.6 

80.0 

76.0 

29.4 

Ratio of rC0 3 +rHC0 3 to rS0 4 .. 

.05 

.26 

6.38 

90.5 

.16 

.13 

8.8 

CONSTITUENTS IN PARTS PER 








MILLION. 








Sodium (Na) and potassium 








(K)«. 

804 

933 

717 

2,872 

544 

3,000 

526 

Calcium (Ca). 

303 

193 

27 

75 

124 

28 

13 

Magnesium (Mg). 

112 

121 

40 

44 

82 

19 

2.6 

Iron oxide (Fe 2 0 3 ) and alumina 








(A1 2 0 3 ). 

14 

19 

3 

56 


Trace. 

4.6 

Sulphate (S0 4 ). 

2,181 

1,673 

170 

23 

1,243 

4,421 

74 

Chloride (Cl). 

404 

606 

332 

2,961 

232 

1,040 

130 

Carbonate (C0 3 )f>. 

76 

282 

686 

1,435 

125 

355 

400 

Sulphide (S). 







83 

Silica (Si0 2 ). 

c 54 

c 249 

95 

c 67 

57 

29 

18 


3,948 

4,076 ’ 

2,070 

7,533 

2,407 

8,892 

1,251.2 

Hydrogen sulphide (H"S). 



104 













REACTING VALUES IN PER CENT. 








Alkalies: 








Sodium (rNa) and potas- 








sium (rK)o... 

29.5 

33.5 

43.5 

47.3 

32.3 

48.9 

48.1 

Alkaline earths: 








Calcium (rCa). 

12.7 

7.9 

1.9 

1.4 

8.5 

.5 

1.4 

Magnesium (rMg). 

7.8 

8.2 

* 4.6 

1.3 

9.2 

.6 

.5 

Strong acids: 








Sulphate (rS0 4 ). 

38.3 

28.7 

5.0 

. 2 

' 35.3 

34.6 

3.2 

Chloride (rCl). 

9.6 

14.1 

13.1 

31.7 

9.0 

11.0 

7.7 

Weak acids: 








Carbonate (rC0 3 )b. 

2.1 

7.6 

31.9 

18.1 

5.7 

4.4 

28.1 

finlnhide (rS)_ 



, 




11.0 









ANALYSIS AS REPORTED.d 








Sodium sulphate. 

96. 76 

100. 33 

14.37 

1.90 

70.80 

382.05 

5. 84 

Sodium chloride.. 

38-93 

56.81 

31.99 

286. 00 

22.37 

100. 30 

12.52 

Sort inm narbnna.t,e 

.66 

1.35 

56. 68 

126.00 


27.54 

39.01 

Snriinm snlrihidfl 







11.85 

Pfl.1r.inm Rnmhatfi 

59.08 

10.12 

. 10 


8. 22 


.50 

Calcium carbonate. 

.82 

20. 76 

3.90 

10. 90 

12.13 

4.07 

1.54 

Ma cmA<3inm siilnha.t.ft 

25.42 

28.53 

.21 


23.77 


Trace. 

Mfl.ffnft<?inm rarhonat© 

4.99 

4. 54 

7. 95 

8. 90 


3. 82 

.52 

Trrm nviriA a/nrl alumina 

. 84 

1.13 

. 16 

3.30 


Trace. 

.27 

Silica. 

c3.15 

c 14. 54 

5. 63 

c 3.90 

3.33 

1.70 

1.03 


230. 65 

238.11 

120.99 

440. 90 

140. 62 

519.48 

73.08 




6.09 














a Reported and calculated as sodium but includes potassium. 
b Reported and calculated as carbonate but probably in part bicarbonate, 
c Includes suspended matter. 

d In hypothetic combinations, in grains per U. S. gallon. 


74,75,76,77. Water from different horizons in four wells of the Associated Oil Co.,sec.36,T.20 S.,R.14 E. 
’ These wells are all within 1,200 feet of a central point, and the four waters probably occur in the 
same vertical section. Analyst, Smith, Emery & Co. Authority, Associated Oil Co. 

74. Water well, 996 feet deep. Water chiefly from about 800 feet, or about 1,000 feet above the oil. 

75 . Oil well. Water corroded casing at 1,160 feet, and probably occurs in water sand at about 1,100 feet. 

Top of oil sand 1,542 feet. „ , „ „ 

76. Oil well. Sulphur water from 1,347 feet. Tar sand 1,170 to 1,205; top of oil sand 1,593 feet. 

77 Oil well. “Bottom water” from 1,802 feet. Oil sand 1,712 to 1,778 feet. 

78 79. Standard Oil Co. well Domengine 1, sec. 27, T. 18 S., R. 15 E. No. 78 represents water from 370 
’ feet; No. 79, water from 3,700 feet, at which depth no oil had been encountered. These analyses 

probably represent the normal changes that occur with increasing depth in waters unaltered by 
the oil. Analyst, Standard Oil Co. . . A . 

80. Water from upper coal mine, sec. 26, T. 20 S., R. 14 E. Water issues from point just above the coal 
bed (in Tejon formation) and is probably unaffected by oil. Analyst, Smith, Emery & t o. 

60439°—Bull. 653—17-6 



















































































82 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

Figure 5, B, shows these two analyses plotted according to the 
scheme followed in figure 5, A, except that the vertical scale used is 
only about half as great. Even on a smaller scale, however, the con¬ 
trast between the two figures is striking. The percentage values of 
sulphate and carbonate, instead of crossing, run practically parallel. 
The alkaline earths decrease greatly and the alkalies therefore increase. 
The percentage of chloride is about the same in the two waters. The 
concentration figure increases greatly, however, so that all these con¬ 
stituents except the alkaline earths increase in actual amount. 
Analyses of water from other deep wells outside the oil fields on the 
west side of the San Joaquin Valley indicate that these changes are 
representive and that the amount of sulphate does not decrease and 
generally increases with depth. 1 In general, the concentration in¬ 
creases and in many localities chloride shows a marked increase with 
depth, but this does not affect the relative proportions of sulphate 
and carbonate. 

The analyses given above show that in the Coalinga field the altera¬ 
tion of the waters as the oil zone is approached is extensive, but in 
the Midway field the changes are less striking. Analyses 81 and 82, 
Table 13, represent waters from the same well at depths of 1,380 
and 1,947 feet, respectively. A gas sand occurs at about 1,810 feet 
and an oil sand a short distance below the lower water, so that the 
section represented is roughly comparable to that shown in the lower 
part of figure 5, A. These waters, however, are of partly connate 
origin and the proportion of sulphate even in the upper water is small- 

The properties of reaction show only a slight change, primary 
alkalinity increasing from 28.6 to 31.8 per cent and the sulphate 
salinity ratio decreasing from 2.3 to 0.2 per cent. The carbonate- 
sulphate ratio shows the most pronounced change, from 20 in the 
upper water to 165 in the lower. There is also a marked difference 
in concentration, that of the lower water being over twice that of the 
upper. It is evident that these waters differ in composition along 
the same fines followed by the Coalinga waters but that the total 
changes are much smaller. In the Midway field water 600 feet apart 
may show only a slight difference in sulphate content, whereas in the 
Coalinga field waters in the same relative positions usually differ 
widely. 


1 Mendenhall, W. C., Dole, R. B., and Stabler, Herman, Ground water in San Joaquin Valley, Cal.: 
U.S. Geol. Survey Water-Supply Paper 398, 1916. 





COMPOSITION OF THE OIL-FIELD WATERS. 83 

Table 13. —Analyses of water from different depths in an oil well in the Midway oilfield, 

Cal. 


PROPERTIES OF REACTION IN 
PER CENT. 

Primary salinity. 

Secondary salinity. 

Primary alkalinity. 

Secondary alkalinity. 

Per cent of rS04 in rSCU+rCl. 
Ratio of rC 03 +rHC 03 to rSC>4. 

CONSTITUENTS IN PARTS PER 
MILLION. 

Sodium (Na) and potassium 

(K)o. 

Calcium (Ca). 

Magnesium (Mg). 

Iron (Fe 2 C> 3 ) and alumina 

(AI 2 O 3 ). 

Sulphate (SO 4 ). 

Chloride (Cl). 

Carbonate (CO 3 ) b ... 

Silica (Si0 2 ). 


81 

82 


81 

82 



REACTING VALUES IN PER 





CENT. 



68.6 

67.0 

Alkalies: 



0 

0 

Sodium (rNa) and potas- 



28.6 

31.8 

sium (rK) a. 

48.6 

49.4 

2.8 

1.2 

Alkaline earths: 






a 

K 

2.3 

.2 

Magnesium (rMg). 

• D 
.8 

. 0 

.1 

20 

165 

Strong acids: 






Q 




Chloride (rCl). 

33'. 5 

33! 4 



Weak acids: 





Carbonate (rCOs) &. 

15.7 

16.5 

1,059 

2,809 

ANALYSIS AS REPORTED. 



11 

26 




9.6 

2.9 

Sodium sulphate. 

3.31 

.76 



Sodium chloride. 

108. 40 

281.50 

1.7 


Sodium carbonate. 

41.64 

121. 80 

38 

8.7 

Calcium carbonate. 

1.65 

3.80 

1,125 

2,920 

Magnesium carbonate. 

1.92 

.61 

443 

1,226 

Iron oxide and alumina. 

.10 


12 

17 

Silica. 

.71 

1.00 

c 2,699.3 

7,009.6 


c 157. 73 

409. 47 


a Reported and calculated as sodium but includes potassium. 
i> Reported and calculated as carbonate but probably in part bicarbonate. 
c Potassium, iodide, and borate absent. 
d In hypothetic combinations, in grains per U. S. gallon. 


81,82. Standard Oil Co. well, sec. 30, T. 32 S., R. 24 E. No. 81 represents water from 1,380 feet and No. 
82 water from 1,947 feet. A small gas sand occurs between the two waters, and an oil sand a short 
distance below the lower. Both samples taken while drilling and analyzed by Standard Oil Co. 


Analyses 83 to 85, Table 14, represent the vertical gradation in the 
Kern River field. As these waters are primary alkaline there is no 
sharp change in character comparable with the change from secondary 
salinity to primary alkalinity in the waters of the west side, but the 
same order of succession is observed, carbonate increasing and sul¬ 
phate decreasing as the oil zone is approached. Analysis 86 repre¬ 
sents water from a depth of 5,135 feet or over 3,000 feet below 
the main oil zone. Although occurring over 3,000 feet below the 
deepest of the waters just mentioned it is very similar to it in charac¬ 
ter, showing high alkalies, chloride, and carbonate, and no sulphate. 1 
However, a water encountered at least 2,500 feet above this in the 
same well close to (probably below) the oil zone is very different in 
character; it is a secondary saline brine rather than a primary alkaline 
water, though as would be expected from its position it contains no 
sulphate. So far as is known, this water is much the most concen¬ 
trated water and is the only brine that has been found in the Kern 
River field. An idea of its composition may be obtained from the 
following partial analysis, 2 and the properties of reaction estimated 
from this analysis' are as follows: Primary salinity 89.5 per cent, 
secondary salinity 10 per cent, secondary alkalinity 0.5 per cent. 


1 Compare analysis 44, Table 7, p. 70, which represents water from a depth of 3,860 feet, or about 3,000 
feet below the oil measures at the northern end of the Midway field. 

2 Mendenhall, W. C., Dole, R. B., and Stabler, Herman, Groundwater in San Joaquin Valley, Cal.: 
U. S. Geol. Survey Water-Supply Paper 398, Table 60, p. 294, 1916. 





























































84 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

I 

Field assay of water occurring between 1,030 and 2,609feet in Petroleum Development Cods 

deep well, sec. 4, T. 29 S., R. 28 E. 

Parts per million. 


Bicarbonate (HC0 3 ). 132 

Sulphate (S0 4 ). 5 

Chloride (Cl). 15,100 

Total hardness calculated as CaC0 3 . 2, 300 

Total solids. i . 25, 000 


Although definite groups of analyses showing the vertical gradation 
in other fields are not available, there is every reason to believe that 
the order of succession is the same. The total extent of the alteration 
may differ in different fields, and the point at which alteration is com¬ 
plete may be higher in some localities than in others, hut these are 
merely local variations which remain to be determined in each field. 
In some localities an incompletely altered water may he found below 
the oil measures, but such occurrences are doubtless due to unusual 
geologic conditions. Thus, analysis 30, already discussed, indicates 
an only partly altered water occurring 600 feet below the oil measures, 
but this water is in Cretaceous strata and has probably had a very 
different history from the altered water more closely associated with 
the oil (analysis No. 64). However, as the migration and accumula¬ 
tion of oil in the fields of the San Joaquin Valley has been greatly 
influenced by angular unconformities in the strata, it is conceivable 
that surface water might enter at the outcrop of a lower formation, 
barren of oil, and migrate through it without complete alteration to 
a point below the oil measures. In a region of such complex geologic 
structure some apparent irregularities in the alteration of the water 
are to be expected. 


i 


% 







COMPOSITION OF THE OIL-FIELD WATERS. 85 

Table 14.— Analyses of waters from various horizons in the Kern River, Lost Hills, and 

McKittrick oil fields, Cal. 



83 

84 

85 

86 

87 

88 

89 

PROPERTIES OF REACTION IN 








PER CENT. 








Primary salinity. 

34.4 

41.6 

12.2 

58.8 

87.6 

94.0 

72.8 

Secondary salinity. 

0 

0 

0 

0 

10.4 

1.6 

0 

Primary alkalinity. 

4.4 

33.0 

76.2 

40.2 

0 

0 

24.0 

Secondary alkalinity. 

61.2 

25.4 

11.6 

1.0 

2.0 

4.4 

3.2 

Ratio of rS0 4 to rS0 4 +rCl. 

62.8 

20.2 

8.0 

0 

5.7 

Trace. 

.6 

Ratio ofrCOs+rHCOs to rS0 4 .. 

3 

7 

88 

OO 

.36 

44.0 

68.0 

CONSTITUENTS IN PARTS PER 


- 






MILLION. 








Sodium (Na). 

l 99 

I a 51 

a 296 

l 1 K£0 

/o4,773 

07,635 

04 ,132 

Potassium (K). 

f 22 

\. 


> l,OOU 

\ . 



Calcium (Ca). 

IS 

13 

20 

10 

214 

195 

38 

Magnesium (Mg). 

4.2 

1.2 

8.6 

1.2 

228 

144 

52 

Iron (Fe) . 

. 1 


f . 

. 1 

} b 16 

5 21 

% 

Aluminum (Al). 


1 5 5 



5 2.7 

Sulphate (Sb 4 ).. 

21 

12 

7.5 

0 

634 

17 

28 

Chloride (Cl). 

9.1 

35 

58 

1,418 

7,744 

11,946 

4,766 

Carbonate (C0 3 ). 

0 

c52 

c384 

0 

c 145 

c464 

cl, 513 

Bicarbonate ('HCO 3 ') . 

71 



1,708 




Silica (Si02). 

18 

23 

52 

46 

48 

67 










127.4 

192.2 

826.1 

3,821.3 

13,800 

20,470 

10,598.7 

REACTING VALUES IN PER CENT. 








Alkalies: 








Sodium (rNa). 

Potassium 

} 19.4 

( o37.3 

a44.2 

} 49.5 

f 043.8 

0 47.0 

o48.4 

Alkaline earths: 


i . 






Calcium (rCa). 

22.2 

11.0 

3.4 

.4 

2.2 

1.3 

.5 

Magnesium (rMg). 

8.4 

1.7 

2.4 

.1 

4.0 

1.7 

1.1 

Strong acids: 








Sulphate (rS0 4 ). 

10.8 

4.2 

.5 

.0 

2.8 

Trace. 

.2 

Chloride (rCl). 

6.4 

16.6 

5.6 

29.4 

46.2 

47.8 

36.2 

Weak acids: 








Carbonate (rCO ; s). 

0 

c29.2 

C43.9 

.0 

cl.O 

c2.2 

c 13.6 

Hinarhonata frH(!()«d _ 

32.8 



20.6 











ANALYSIS AS REPORTED. 








fin^inm Qiilnhatfi 


1.05 

.65 





Sodium r.hloride . 


3.39 

5.56 


705.65 

1,116.23 

459.11 

Sndinm carbonate . 


3.01 

34.30 


1.79 

14.30 

139.32 

P.ntcinm sn Inhate. 





40.58 

1.42 

.71 

Pfllpinni ohloridP) 






6.85 


Pn.lc.iirm carbonate . 


1.88 

2.96 


1.35 

21.15 

5.01 

\f q cm AQi’nm <;nlnhatA 





10.50 


1.40 

MfHrnpciiim oh 1 or id 0 





33.25 

22.93 

.27 

Macroo^inm carbonate 


.26 

1.75 


9.36 

8.93 

9.30 

Tron and alnmina .. 


.30 



.92 

1.20 

.16 

Silica... 


1.36 

3.06 


2.69 

2.83 

3.89 











11.26 

48.28 


806.09 

1,195.84 

619.17 


a Reported and calculated as sodium but Includes potassium. 

5 Fe203+Al2C>3. 

c Reported and calculated as carbonate but probably m part bicarbonate. 
d In hypothetic combinations, in grains per U. S. gallon. 


85. 

86 . 


Kern River field: , , . „ . . , 

83 Kern River water at Bakersfield. Mean of 35 analyses of samples collected every 10 days m 
1906. Analysts, F. M. Eaton and P. L. McCreary (U. S. Geol. Survey Water-Supply Paper 

84. Standard 5 O il Co ? water well, sec. 5, T. 28 S., R.27 E. Water from 380 to 397 feet. Analyst, Stand¬ 
ard Oil Co., October, 1913. „ . , . 0MO , , . , 

Standard Oil Co. well 1, sec. 27, T. 28 S., R. 27 E. Water from 1,990 feet to 2,018 feet or about 
200 feet above tar and oil sands. Analyst, Standard Oil Co., January, 1915. # 

Petroleum Development Co., see. 4, T. 29 S., R. 28 E. Well 5,135 feet deep. Water is from brown 
shale, containing shows of oil, but over 3,000 feet below producing oil zone. (U. S. Geol. Survey 
Water-Supply Paper 398, Table 61, p. 294, 1916.) 

Lost Hihs^fieM. Incorporated 0jl Co well sec 7> T- 2 7 S., R. 21 E. Water from 180 feet, and probably 

not affected by oil. Analyst, Smith, Emery & Co. , ,, , 

88 Associated Oil Co. well 3, sec. 13, T. 26 S., R. 20 E. Water probably from a short distance above 
the oil. Analyst, Smith, Emery & Co. Authority, Associated Oil Co. 

MC ^9 1 Associated Oil Co. well Del Monte 38, sec. 18, T. 30 S., R. 21 E. Water pumped with the oil. 

Analyst, Smith. Emery & Co. Authority, Associated Oil Co. This analysis is typical of the 
water associated with the oil in the McKittrick field. 










































































































86 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


AREAL RELATIONS. 

The oil-field waters vary horizontally as well as vertically, but the 
horizontal or areal variation is due simply to the mingling in various 
proportions of meteoric and connate waters. No matter how effect¬ 
ually connate water may be trapped in a structural trough, it is evi¬ 
dent that near the surface of the ground and also around the edges 
of the trough where the rocks outcrop there will be a certain admix¬ 
ture of meteoric water. Although a few very salty waters have been 
found close to the surface (see No. 87, Table 14, p. 85) they are gener¬ 
ally confined to lower levels, and a marked increase of alkalies and 
chlorides with depth appears to be the rule. This phase of the mixing 
of fresh and salt waters has been sufficiently discussed in the preceding 
section, and the gradation from the outcrop toward the center of the 
trough will now be considered. Two phases of this gradation present 
themselves, first, the increase in chloride, which is a factor of simple 
mixing, and second, the change in the properties of the water, which 
is the net result of various chemical reactions. Since the chloride is 
not affected by hydrocarbons it furnishes a simple and convenient 
basis for comparing normal and modified as well as altered waters. 
The properties of reaction, however, furnish a more adequate basis 
for comparison and in studying waters of the altered group are espe¬ 
cially valuable. 

The examples given below are drawn from the Midway and Sunset 
fields, where it happens that the most complete data are available, but 
similar gradations have been observed in the Coalinga field and can 
doubtless be worked out elsewhere. 

Variation in chloride .—Normal connate water contains about 19,000 
parts per million of the chloride radicle and 16,000 parts of other con¬ 
stituents; ordinary surface water contains very little chloride and 
generally less than 3,000 parts of dissolved solids. The figures repre¬ 
sen ting chloride and total solids show the greatest contrast and are 
therefore convenient indices for comparing mixtures of the two types. 
The carbonate figure also shows considerable variation, being very 
low in brine and generally higher in meteoric water. 

In the accompanying table are shown a series of partial analyses 
of water from wells near Fellows in the northern part of the Midway 
field. The wells fall roughly along a line about coincident in direction 
with the dip of the strata. In the table they are arranged in order of 
their distance from the outcrop—American Oilfield Co.’s well 92 being 
about 1,600 feet from the outcrop and Associated Oil Co.’s well 3 
about 10,000 feet beyond well 92. The analytical figures given for 
the water from the first four wells represent partial analyses made by 
the American Oilfields Co.; the figures given for the water from the 
last two wells are taken from complete analyses made by Smith, 




COMPOSITION OF THE OIL-FIELD WATERS. 


87 


Emery & Co. for the Associated Oil Co. The chloride values are 
accurately determined and are comparable throughout. The figures 
reported for soluble solids in the first four analyses are assumed to 
represent all the constituents except silica and the alkaline earth car¬ 
bonates, and on this basis are comparable with the figures shown for 
the last two analyses. The “alkalinity” values of the first four 
waters are mutually comparable but do not represent alkalinity in 
the sense used elsewhere in this report; no comparable figures for the 
last two waters are available, but their alkalinity is known to be con¬ 
siderably lower than that of the others. 


Partial analyses of water from oil wells near Fellows, Midway field, showing increase of 

salinity with distance from the outcrop. 



Parts per million. 

“Alka¬ 
linity,” 
per cent. 

Chloride 

(Cl). 

Soluble 

solids. 

American Oilfields Co. well 92. 

400 
2,840 
7, 720 
14,480 
17,631 
24,398 

6,630 
8,660 
20, 720 
26,480 
28,970 
39, 700 

0.01300 

.01350 

.01158 

.00625 

American Oilfields Co. well 73. 

American Oilfields Co. well 57. 

American Oilfields Co. well 23. 

Associated Oil Co. well 7°. 

Associated Oil Co. well 3.. 





a See analysis 50, Table 8, p. 73. 


In order to show these relations graphically the determinations 
have been plotted in figure 6. In the figure the horizontal scale repre¬ 
sents the distance between the wells along a line between American 
Oilfields Co.’s well 92 and Associated Oil Co.’s well 3. All the wells 
fall close to this line except Associated Oil Co.’s well 7, which lies 
about 1,200 feet to the northwest. The figure shows fairly well the 
gradation from an essentially meteoric water to a connate water. If 
an analysis of water from still nearer the outcrop could be added it 
would doubtless show a still smaller amount of solids. On the other 
hand, the water from Associated Oil Co.’s well 3 is somewhat more 
concentrated than sea water and contains a slightly larger amount 
of chloride, and waters from points still farther from the outcrop do 
not show any further increase. 

The remarkably regular increase in chloride and soluble solids 
shown by these analyses is not entirely a horizontal gradation, for the 
waters are not all from the same horizon. The water in American 
Oilfields Co.’s well 92 probably occurs about 600 feet stratigraphically 
higher than that in the Associated Oil Co.’s wells. This is suggested 
by the slight irregularities in the curves shown in figure 6, but the 
vertical component is not great enough to detract seriously from the 
significance of this regular and essentially horizontal gradation. 





















88 OIL-FIELD WATEKS IN SAN JOAQUIN VALLEY, CAL. 

Relations of the mixed type .—Besides causing a simple variation in 
the chloride content the mingling of connate and meteoric waters 
leads to a series of reactions between the other constituents and pro¬ 
duces corresponding changes in the properties of the waters. These 
changes may he observed in the waters of any one zone along a line 
leading away from the outcrop, but may best be studied in the waters 
of the altered group, whose complete alteration by the oil affords a 
uniform basis for comparison. The fact that the altered waters along 
the western or shallow edge of the Midway and Sunset fields are of 
the chloride-carbonate type, whereas those farther east are secondary 
saline brines, is due to the entrance of meteoric water at the outcrop, 


S W. Distance between wells In feet NE. 



Figure 6. —Diagram showing increase in salinity of waters in the northern part of the Midway field with 

distance from the outcrop. 


and the gradations that may be traced between this mixed type and 
the brines afford an interesting study of the mixing of meteoric and 
connate waters. The relations and derivation of the mixed type 
may more easily be understood if some of the reactions involved are 
first considered. 

The reactions involved in the conversion of a sulphate water into a 
carbonate water, which forms the basis of the vertical gradation 
already described, are discussed on pages 94-99. Let it be assumed 
for the present that the process is a simple substitution of carbonate 
for sulphate. In unaltered sea water sulphate and chloride exceed 
the alkalies in value and are therefore partly in equilibrium with the 
alkaline earths; hence, if carbonate is substituted for the sulphate the 
alkaline earths will be partly in equilibrium with carbonate. Only a 








































COMPOSITION OP THE OIL-FIELD WATERS. 


89 


small amount of earths and carbonate can be retained m solution, 
even in the presence of an excess of carbon dioxide, and if this amount 
is exceeded alkaline earth carbonates will be formed and then lost 
through precipitation. In a concentrated solution like sea water the 
maximum value of alkaline earths balanced by carbonate that can 
be retained represents only a very small percentage of the total con¬ 
centration value, and if the sulphate is entirely replaced by carbon¬ 
ate a large proportion of this carbonate, with an equivalent value 
of earths, will be precipitated. 1 The effect on the properties of reac¬ 
tion of this substitution and consequent loss therefore consists in a 
decrease in secondary salinity and an increase in secondary alkalinity 
limited by the solubility of the alkaline-earth carbonates. Sea water is 
characterized by 21.1 per cent of secondary salinity, of which 9.2 per 
cent is contributed by sulphate; hence, the removal of the sulphate 
will effect a substantial reduction in the secondary salinity. The 
increase in secondary alkalinity, however, will be slight, so that if 
the properties are expressed in percentages the value of primary 
salinity will be raised. If it be assumed, first, that the sulphate in 
sea water is entirely removed and an equal value of carbonate intro¬ 
duced, and secondly, that 7.6 per cent, or 2,660 parts per million of 
alkaline-earth carbonates are lost through precipitation, the proper¬ 
ties will change as follows: 


Changes in properties of sea water through substitution of carbonate for sulphate. 



Primary 

salinity. 

Secondary 

salinity. 

Secondary 

alkalinity. 

Concentra¬ 

tion. 

Normal sea water. 

78.6 

21.1 

0.3 

35,000 

Sea water in which all SOUs calculated as CO 3 . 

78.6 

11.8 

9.6 

35,000 

Same after precipitation of assumed excess of alkaline 
fiart.h carbons,tos _ . 

85.1 

12.8 

2.1 

32,340 




Since these reactions take place after the water has been entrapped 
in the sediments they are of course complicated by many indeter¬ 
minable factors, and any attempt to reduce them to exact figures must 
be regarded as speculative. There is little doubt, however, that 
the oil-field brines have been derived from connate water by the 
general processes outlined above, as shown by their properties of 
reaction. (See Tables 8 and 9.) 

The changes involved in the alteration of a meteoric water are 
similar but more extensive. The chief constituents of the surface 
and shallow ground waters of the fields of the west side are sulphate, 
- alkalies, and alkaline earths. (See Tables 1 to 4.) If carbonate 
is substituted for the sulphate in these waters, it may be pre- 

1 Murray, John, and Irvine, Robert, On the chemical changes which take place in the composition of the 
sea water associated with blue muds on the floor of the ocean: Roy. Soc. Edinburgh Trans., vol. 37, p. 481, 
1892-93. 



















90 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

sumed that a considerable proportion of alkaline earth carbonates 
will be formed and removed by precipitation, leaving the chief con¬ 
stituents of the water alkalies and carbonate. These waters, how¬ 
ever, are less concentrated than sea water, and therefore the amount 
of alkaline earths that can be held in solution in the presence of 
carbonate, if expressed as a percentage, will he much greater. The 
alteration of a meteoric water results essentially in a change from 
primary and secondary salinity to primary and secondary alkalinity, 
the percentage of the last property being only moderate. These 
changes are partly shown by the first three analyses in figure 5, A, 
and the complete transition from normal through modified to altered 
waters of meteoric origin by the analyses in Tables 4, 5, and 6. 

Altered waters of the mixed type are derived by the mixing of 
primary alkaline waters (reversed type) and brines. It has been 
shown above that if all of the sulphate is removed from sea water 
and carbonate substituted the resulting brine will still be charac¬ 
terized by a considerable proportion of secondary salinity, which 
must be chloride salinity. The reaction that ensues when a sodium 
carbonate water is added may be written thus: 

Secondary salinity+Primary alkalinity=Primary salinity-f-Secondary alkalinity 
CaCl 2 + Na 2 C0 3 = 2NaCl + CaC0 3 

The addition of a primary alkaline water to a brine increases the 
alkalies without corresponding increase in strong acids and second¬ 
ary salinity is therefore reduced. Secondary alkalinity may be some¬ 
what increased, as the concentration of the brine is decreased by 
the addition of the more dilute water, but this change is not likely 
to be pronounced. If a sufficient amount of the sodium carbonate 
water is added it is evident that all the secondary salinity will be 
destroyed and that the water will then be characterized by only two 
properties, primary salinity and secondary alkalinity. (See analysis 
46, Table 8, p. 73.) Any further increment of sodium carbonate 
water will then introduce primary alkalinity, which will continue to 
increase as more of the carbonate water is added. The average 
concentration of most of the brines is about 35,000 parts, whereas 
that of most of the primary alkaline (meteoric) waters is only about 
3,000 parts; hence, the concentration of the mixed water will be 
some intermediate figure, depending on the proportions of the mixture. 
If the brine component predominates primary salinity and the con¬ 
centration will be high and primary alkalinity low, but as more and 
more of the meteoric water is added primary alkalinity will increase 
and primaiy salinity and concentration will decrease. (See analyses 
60, Table 10, p. 76, and 72, Table 11, p. 77.) 

The transition from brine to the mixed type is shown in figure 7, 
in which are plotted the reaction properties of the waters from four 
wells along the -east-west line that separates the Midway and Sunset 


COMPOSITION OF THE OIL-FIELD WATERS. 


91 


fields. This line is oblique to the strike of the beds and the changes 
are therefore more gradual than they would be along a line normal 
to the strike. The total distance is about 18,300 feet, the wells being 
equally spaced. All the waters occur below the top oil sand and are 
believed to come from the same general horizon. 

Complete analyses of the waters are given in Tables 9 and 11 (pp. 74 
and 77). As shown in figure 7, the waters of the two wells near the 
outcrop are primary alkaline, whereas those farther east are brines. 
With distance from the outcrop there is a marked decrease in primary 
alkalinity, which if continued would lead to the total disappearance 
of this property at some point between the second and third wells. 


Distance between wells in feet 



Figure 7.— Diagram showing gradation between waters of the mixed type in the western part of the 
Midway-Sunset field and the brines that occur at the same general horizon in the deeper territory to the 
east. Section extends from SE. \ sec. 31, T. 32 S., It. 24 E., to NE. £ sec. 31, T. 12 N., R. 23 W. 


In the same direction there is a corresponding rise in primary salinity, 
indicating that at some point the water is characterized by only two 
properties. East of this point primary salinity decreases and sec¬ 
ondary salinity appears, rising to 16.2 per cent in the water farthest 
from the outcrop. The concentration curve shows a steady rise with 
distance from the outcrop, and in the distance covered by the figure 
more than trebles. It will be noted that there is much less differ¬ 
ence between the waters of the two wells farthest from the outcrop 
than between those of the two nearest, indicating that beyond a 
certain point the infiltration of meteoric water is negligible. Beyond 
the farthest well the brine shows no further changes and is fairly 
uniform in composition. Between the first well and the outcrop, 
however, the water probably increases rapidly in primary alkalinity 
and near the outcrop passes to the reversed type. 
































92 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


The belief that this chloride-carbonate water, which is associated 
with the oil in the Westside Coalinga and in the western or shallower 
portion of the Midway and Sunset fields, is in reality a mixture of 
meteoric and connate waters is corroborated by other observations. 
Thus, the average ratios of magnesium to calcium and of sodium to 
potassium in waters of the mixed type are intermediate between those 
in the brines on the one hand and in the chiefly meteoric waters on the 
other. These ratios have been calculated in all the analyses given 
in this report, and the averages for each type are presented in the 
following tables. For the purposes of this comparison it may be 
assumed that all the waters of the normal and modified groups and 
of the reversed type of the altered group are essentially of meteoric 
origin. As practically all these waters contain some of the con¬ 
stituents of connate water, whereas the brines are relatively pure, 
the mixed type would be expected to resemble the essentially 
meteoric waters more closely than the brines. Thus, the average 
ratio of magnesium to calcium in 16 waters of the mixed type is 1.29, 
as against 1.34 in 50 chiefly meteoric waters, and 0.71 in 13 brines. 
Sodium and potassium have been separately determined in only 16 
of the analyses in this report, so that the average ratios are of less 
value. The average sodium-potassium ratio in 6 waters of the 
mixed type is 188, as against 246 in 6 chiefly meteoric waters and 
165 in 4 brines. Although in the deeper waters the individual ratios 
of both magnesium to calcium and sodium to potassium are fairly 
constant, in the upper meteoric waters they show considerable varia¬ 
tion; hence if twice as many analyses were included the figures would 
be somewhat different. That the figures given may fairly be consid¬ 
ered representative, however, is indicated by the writer’s study of a 
large number of analyses not included in this report. 


Average ratios of magnesium to calcium in reacting values in 7.9 analyses of dif¬ 

ferent ty-pes of water from the Coalinga, Midway, and Sunset fields. 


> 


Type of water. 

• i 

Coalinga field. 

Midway-Sunset 

field. 

Both fields. 

Average 

ratio. 

Number 

of 

analyses. 

Average 

ratio. 

Number 

of 

analyses. 

Average 

ratio. 

Number 

of 

analyses. 

Surface water. 

3.08 

2 

0.90 

5 

1.52 

7 

Ground water: 






Normal. 

1.04 

18 

1.35 

4 

1.09 

22 

Modified. 

.90 

4 

1.70 

3 

1.25 


Reversed. 

1.70 

12 

1.65 

2 

1.69 

14 

Brine. 

.90 

1 

.70 

12 

.71 

13 

Mixed. 

1.62 

5 

1.15 

11 

1.29 

16 

Averages: 

All meteoric waters.•_ 





1.35 

36 

1.31 

14 

1.34 

50 

All types. 

1.37 

42 

1.06 

37 

1.23 

79 































CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 93 


/rNa\ 

Average ratios of sodium to potassium in reacting values i \ 

Coalinga, Midway , and Sunset fields. 


in 16 waters from the 


Average 

ratio. 


Chiefly meteoric water 

Mixed type. 

Brine. 

Average of all types... 


246 

188 

165 

204 


Number of 
analyses. 


. 6 
6 
4 

16 


CHEMICAL RELATIONS BETWEEN WATER AND THE 

HYDROCARBONS. 

ALTERATION OF WATERS BY THE HYDROCARBONS. 

NATURE OF ALTERATIONS. 

It has been shown that the waters associated with the oil in the 
San Joaquin Valley oil fields are almost or quite sulphate-free, not¬ 
withstanding the fact that the shallower waters of the region are 
characterized by a large concentration of sulphate. An equally 
striking feature of many of the waters associated with the oil is the 
presence of alkali carbonate, which is lacking in the shallow waters 
on the west side of the valley. Between the sulphate and carbonate 
zones is a zone characterized by waters carrying hydrogen sulphide. 
Outside the oil fields sulphate and carbonate maintain the same 
mutual proportions to great depths and hydrogen sulphide waters 
are rare; the conclusion is therefore irresistible that a change in the 
composition of the oil-field waters has been caused directly or indi¬ 
rectly by constituents of the oil or gas. As sulphate is abundant in 
the shallower waters everywhere on the west side of the San Joaquin 
Valley, whereas sulphide is found only near the hydrocarbons, it is 
reasonable to suppose that the sulphide has been derived under special 
conditions through reduction of the sulphate. In regions where sul¬ 
phates are rare or only locally distributed the alternative hypothesis— 
that sulphide has accompanied the oil from below and that sulphate 
is formed by its oxidation—may have to he considered, but as this 
condition does not prevail in the oil fields of San Joaquin Valley this 
hypothesis need not be discussed. 

REDUCTION OF SULPHATE. 

The observation that waters associated with oil contain no sulphate 
is by no means new, for it was pointed out in 1882 by Potiiitzin 1 that 
the waters associated with oil in the Caucasian oil fields contain no 
sulphate, and this has been amply confirmed by later workers there 

i Potiiitzin, A., Zusammensetzung des die Naphta begleitenden und aus schlammvulkanen ausstro- 

menden Wassers (abstract): Deutsche chem. Gesell. Ber., Band 15, p. 3099-b, 1882. 














94 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

and in other fields. Hofer 1 mentions this widespread peculiarity of oil¬ 
field waters and presents a compilation of 27 analyses of sulphate- 
free water from various fields in Europe, Asia, and North America. 
However, neither Hofer nor, so far as the writer knows, any other 
writers on this subject have attempted to work out the chemical 
relations of the various types of water in any one field, hut present 
merely isolated analyses of “oil-field water,” the position of which 
with regard to the oil is generally not stated. The waters differ 
widely in chemical composition, some of them being concentrated 
brines very high in secondary salinity and others closely resembling 
the mixed (carbonate) type found in the San Joaquin Valley fields. 
The mixed type is less common but appears to be characteristic of 
the Russian and Galician fields. The nearly pure alkali carbonate 
water (reversed type) found in the Eastside Coalinga field has appar¬ 
ently not been found elsewhere. Some of the analyses show unusually 
large amounts of iodine and bromine, and several other rare elements 
have been reported, but the common characteristic of all the waters 
examined is the absence of sulphate. In some waters this is so com¬ 
plete that barium salts have been found in the solution. 2 

The earlier investigators apparently regarded these sulphate-free 
waters more as chemical curiosities than as normal and reasonable 
phenomena, but the absence of sulphate has since been attributed to 
the reducing action of the hydrocarbons. The reaction between sul¬ 
phate and organic matter was suggested by Bischof 3 to explain the 
origin of certain sulphur deposits. It is supposed that the sulphate 
is reduced to sulphide, which passes off as hydrogen sulphide, and 
that an equivalent portion of the oil or gas is oxidized to carbon 
dioxide and carbonate. Hofer writes the reaction substantially as 
follows: 

CaS0 4 + CH 4 = CaO + H 2 S + C0 2 + H 2 0 
or 

CaS0 4 + CH 4 = CaS + C0 2 + 2H 2 0 = CaC0 3 + H 2 S + H 2 0 
These reactions, however, are hypothetic and are open to several 
objections. It has long been known that sulphate solutions are 
decomposed under some conditions in the presence of organic matter 
with the formation of hydrogen sulphide. 4 It was shown by Meyer 5 
and more definitely by Plauchud, 6 however, that this decomposition 

1 Engler, C., and Hofer, H., Das Erdol, Band 2, p. 28, 1909. 

2 Idem, p. 28. 

3 Bischof, G., Chemische und physikalische Geologie, 2, pp. 144-164,1851. 

4 Lersch, B. M., Hydro-chemie, pp. 235-238, Berlin, 1864. Clarke, F. W., The data of geochemistry, 
3d ed.: U. S. Geol. Survey Bull. 616, p. Ill, 1916. 

5 Meyer, Lothar, Chemische Untersuchung der Thermen zu Landeck in der Grafschaft Glatz: Jour, 
prakt. Chemie, Band 91, pp. 5-6, 1864. 

3 Plauchud, E., Recherches sur la formation des eaux sulfureuses naturelles: Compt. Rend., vhl. 84, p. 
235, 1877; Sur la reduction des sulfates par les sulfuraires, et sur la formation dessulfures metalliques, 
naturels: Idem, vol. 95, p. 1363,1882. Etard, A., and Olivier, L., De la reduction des sulfates par les 
gtres vivants: Idem, vol. 95, p. 846, 1882, 




CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 95 

is due not to the mere presence of dead organic matter but to the 
vital processes of microorganisms. Numerous observers have since 
studied these creatures, whose functions are diverse 1 and whose 
importance from the standpoint of geochemistry appears to be consider¬ 
able. It has been found that certain bacteria have the function of re¬ 
ducing sulphate to sulphite or thiosulphate and that others reduce 
oxygenated sulphur compounds to hydrogen sulphide. 2 On the other 
hand, certain bacteria can exist only in solutions containing hydrogen 
sulphide, which they oxidize and secrete as sulphur. This sulphur is 
further oxidized in the course of metabolism to sulphate, but the 
excess of sulphur remaining in the organism after death may accumu¬ 
late to form deposits of crystalline sulphur. 3 In general, the sulphide- 
producing bacteria are anaerobic, being able to exist in the absence 
of air, whereas those which secrete sulphur are probably aerobic. 
The hydrogen sulphide in many natural waters is thus doubtless 
derived from aqueous sulphate solutions by the action of bacteria. 

The action of similar organisms in ocean water has also been 
studied. Van Delden, 4 in experimenting with a species that inhabits 
the estuaries on the coast of Holland, finds that these bacteria 
liberate in 27 days 843 milligrams of hydrogen sulphide per liter, 
which represents the reduction of 1,984 milligrams of sulphur trioxide. 
In this experiment he used sea water, to which was added a little 
potassium phosphate and organic matter; in another experiment 
with the same bacteria he used a prepared solution containing 
slightly more sodium chloride and more sulphate than sea water, 
and found that in 19 days 1,030 milligrams of hydrogen sulphide, 
equivalent to 2,424 milligrams of sulphur trioxide, were liberated. 
In the latter experiment the amount of sulphate reduced slightly 
exceeds that present in normal sea water. Van Delden notes also 
that the activity of this species increases with the concentration of 
sodium chloride up to 60,000 parts per million, but that the addi¬ 
tion of more sodium chloride produces a marked diminution in their 
activity. 

Hydrogen sulphide has been repeatedly observed in sea water 
and has been quantitatively determined by several observers. 
Lebedinzeff 5 & finds that water from a depth of 8,290 feet in the 

1 Winogradsky, Sergius, Ueber Schwefelbacterien: Bot. Zeitung, Nos. 31 to 37, 1887. 

2 See, for example, Beyerinck, M. W., Ueber Spirillum desulfuricans als Ursache von Sulfatreduction: 
Centralbl. Bakteriologie, Band 1, Abt. 2, pp. 1-9, 49-59, 104-114, 1895. Also Saltet, R. H., Ueber Reduk- 
tion von Sulfaten in Brackwasser durch Bakterien: Idem, Band 6, Abt. 2, p. 648,1900. 

a For a summary see Stutzer, O., Die Wichtigsten Lagerstatten der Nicht Erze, Berlin, 1911; Phalen, 
W. C., The origin of sulphur deposits (translation from Stutzer’s work): Econ. Geology, vol. 7, pp. 732- 
743, 1912. 

4 Van Delden, A., Beitrag zur Kenntnis der Sulfatreduktion durch Bakterien: Centralbl. Bakteriologie, 

Band 11, Abt. 2, pp. 92-94, 113-119, 1903. 

& Lebedinzeff, A., Vorlaufige Mitteilung iiber den chemischen Untersuchungen des Schwarzen und 
Asowischen Meeres in Sommer 1891: Soc. Naturalistes ft Odessa Trav., vol. 16, fasc. 2, p. 149, 1891; abstract 
in Roy. Geog. Soc. Proc., new ser., vol. 14, p. 461, 1892. 






96 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

Black Sea contains 6,550 parts per million of hydrogen sulphide, 
and Zelinsky 1 has identified in the bottom muds of the Black Sea 
several species of anaerobic bacteria that are very active in the 
formation of hydrogen sulphide. Murray and Irvine 2 report the 
formation of unstable sulphide in sea water associated with the blue 
muds on the floor of the ocean and by a series of analyses show that 
some of the sea water drained from the muds contains only 50 per 
cent as much sulphate as normal sea water. They note a con¬ 
comitant increase in the alkalinity of the water, due principally to 
the formation of carbonate, and a slight loss of lime, due to the 
precipitation of calcium carbonate. This implies a decrease in 
secondary salinity and an increase in secondary alkalinity, limited 
by the solubility of the calcium carbonate; or, in other words, an 
approach to the oil-field brines along the lines explained above. 

It is therefore well established that sulphate may be reduced by 
bacteria in the presence of organic matter, but the bearing of this 
process on the development of the composition of oil-field waters 
is conjectural. It may be assumed, if desired, that the connate 
water was completely altered by the action of bacteria shortly after 
being entrapped in the sediments, as suggested by the observations 
of Murray and Irvine, but the alteration of the meteoric water is 
more difficult to explain. There is no evidence to show that even 
anaerobic bacteria can continue to exist in the muds after they 
have been covered with a thousand feet or more of other sediments 
and elevated into land, and certainly some time must have elapsed 
after the elevation before meteoric water penetrated to the zone of 
alteration. In fact, the writer is inclined to believe that in some 
localities meteoric waters are percolating down to this zone and are 
being reduced at the present time. Hence, unless it be assumed that 
bacteria are present in the strata to depths of several thousand feet 
the formation of the sulphate-free waters can not be ascribed to 
bacterial action, except perhaps in part. 

The belief that hydrocarbons can reduce sulphate at moderate tem¬ 
peratures in the absence of bacteria has been tacitly accepted for 
many years, and few attempts have been made to prove it in the 
laboratory. In the anhydrous condition gypsum (CaS0 4 ) is a very 
stable compound, and it has been found that a temperature of 
about 700° C. is required for its reduction, even with a fairly active 
reducing agent, such as carbon monoxide. 3 In solution, however, 

1 Zelinsky, N. [Sulphydric fermentation in the Black Sea]: Russ. Chem. Soc. Jour., vol. 25, pp. 298-303, 
1894; abstract in Chem. Soc. Jour., vol. 66, pt. 2, p. 200, 1894. Andrussow, N., Physical exploration in 
the Black Sea: Roy. Geog. Soc. Geog. Jour., vol. 1, p. 49, 1893. 

2 Murray, John, and Irvine, Robert, On the chemical changes which take place in the composition of 
sea water associated with blue muds on the floor of the ocean: Roy. Soc. Edinburgh Trans., vol. 37, p. 
481, 1892-93. 

3 IJofman, II. O., and Mostowitsch, W., The reduction of calcium sulphate by carbon monoxide and 
carbon, and the oxidation of calcium sulphide: Am. Inst. Min. Eng. Bull., pp. 913-939, 1910. 




CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 97 

sulphate is more readily reduced. The experiments of the earlier 
y orkers are discredited by the fact that no precautions were taken 
to exclude bacteria, and certain more recent attempts proved unsuc¬ 
cessful, but recently Kharitschoff 1 has published a note on some 
simple experiments that were at least partly successful. He studied 
mixtures of equal volumes of 10 per cent sodium sulphate solution 
and kerosene or benzene under different conditions of temperature 
and pressure. Cadmium chloride was used to indicate the formation 
of sulphide. Three samples exposed to direct sunlight for six months 
at ordinary temperatures showed no sign of reduction. Other sam¬ 
ples, sealed and heated for 420 hours on a water bath, under which 
conditions a pressure of not less than three atmospheres must have 
been developed, showed a very faint coloration due to the formation 
of a trace of sulphide. In still other samples left open and heated 
for 420 hours at 96° C. some sulphide was formed. A solution of 
magnesium sulphate mixed with kerosene and heated in the open 
for 420 hours underwent somewhat more reduction than the solu¬ 
tion of sodium sulphate. Kharitschoff concludes from these experi¬ 
ments that the reduction of sulphate can be accomplished by hydro¬ 
carbons, but that high pressure and temperature during a long period 
of time are necessary to insure complete reduction. 

If it be admitted that the reduction of sulphate is accomplished 
directly by the constituents of oil it must still be recognized that the 
reaction as generally written, involving methane, is improbable. 
Methane, being itself a decomposition product, is the most stable 
member of the paraffin series, which are the most inert of the hydro¬ 
carbons; and although methane becomes much more active at higher 
temperatures and pressures it seems that the reduction of a sulphate 
solution would be accomplished less readily by this hydrocarbon 
than by others. The different members of the hydrocarbon series 
probably react with sulphate solutions in different degree, but this 
phase of the subject has apparently not been investigated. The un¬ 
saturated chain compounds, such as the olefines, acetylenes, and ter- 
penes, doubtless behave in different manner from the paraffins, the 
naphthenes, or the aromatic hydrocarbons, not only in the ease of 
reaction but in the stages involved. In the reactions between some 
substances hydrolysis is probably important, and in those between 
other substances the action of oxidizing agents may enter. It is 
quite possible that certain constituents of the oil other than true 
hydrocarbons are active in the reduction' of sulphate solutions, 
although for the sake of brevity the term hydrocarbon is used in this 
report to include all oil constituents. In any event, the reaction as 
written by Hofer (p. 94) can be considered only a condensed repre- 


i Kharitschoff, K. V., The waters in petroleum wells: Petroleum Rev., vol. 29, p. 368, 1913. 
60439°—Bull. 653—17-7 






98 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


sentation of the type of change that takes place, the intermediate 
stages in the decomposition of the hydrocarbons on the one hand 
and of the sulphate on the other being as yet unknown. 

Just as sulphate by reduction yields sulphide, so sulphide under 
other conditions may oxidize to sulphate. Whether alkaline sul¬ 
phide is the first product of reduction or not, the final product is 
hydrogen sulphide, and this gas is readily oxidized to produce free 
sulphur, probably in accordance with the equation 

2H 2 S + 0 2 = 2H 2 0 4- 2S 

Thus, free sulphur has been found in a number of marine muds, 
where it is doubtless formed by the oxidation of hydrogen sulphide 
derived from the sulphate in the sea water. 1 Under more strongly 
oxidizing conditions, or in the presence of certain bacteria, the sulphur 
becomes thiosulphate, sulphite, and finally sulphate. The com¬ 
plete reversion of hydrogen sulphide to sulphate is probably not 
widespread in deeply buried strata, but the change to free sulphur, 
which may take place even on the floor of the ocean, must be taken 
into account. It may also be noted that the oxidation of hydrogen 
sulphide to sulphur or sulphate results in the evolution of much 
heat, 2 3 * and if the earth temperatures in oil regions are higher than 
elsewhere, as suggested by Koenigsberger and Muhlberg, 8 some of 
the excess may be contributed by this reaction. 

FORMATION OF CARBONATE. 

In the few published accounts of oil-field waters special stress is 
laid on the absence of sulphate as discussed in the preceding section, 
but no attempt has been made, so far as the writer can learn, to work 
out the relations of the various types of water or to explain the sig¬ 
nificance of the carbonate. If the reduction of the sulphate is to be 
ascribed to the action of hydrocarbons, however, the formation of 
carbonate is a necessary concomitant, and the presence of unusual 
amounts of carbonate in oil-field waters may be explained by this 
reaction. 

The proportion of carbonate formed during the reduction of a 
definite amount of sulphate is not known and can not be determined 
until the stages involved in the reaction have been critically studied. 
Murray and Irvine report that the increase in the alkalinity of sea 
water associated with bottom muds is proportional to its loss in sul- 

1 Buchanan, J. Y., On the occurrence of sulphur in marine muds and nodules, and its bearing on their 
mode of formation: Roy. Soc. Edinburgh Proc., vol. 18, p. 17, 1890-91; Clarke, F. W., The data of geo¬ 
chemistry, 3d ed.: U. S. Geol. Survey Bull. 616, p. 514,1916. 

2 Becker, G. F., Geology of the quicksilver deposits of the Pacific slope: U. S. Geol. Survey Mon. 13, 
p. 254,1888. 

3 Koenigsberger, J.,and Muhlberg, M., Uber Messungen der geothermischen Tiefenstufe: Neues Jahrb., 

Beilage Band 31, pp. 107-157, 1911. 



CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 99 

phate, but this observation merely indicates that the two changes are 
the result of the same process and does not throw much light on the 
proportions involved. In the transition from normal to altered 
waters in the oil fields the increase in carbonate is roughly propor¬ 
tional to the decrease in sulphate, but the loss by precipitation of 
alkaline-earth carbonates prevents the deduction of exact figures. 
The assumption made on page 88 that for the value of sulphate re¬ 
moved from the water an equivalent value of carbonate is intro¬ 
duced, is perhaps the best that can be made at the present time and 
is fairly adequate if the water alone is considered. As a matter of 
fact, however, the waters in the zone of alteration contain sufficient 
half-bound carbon dioxide to allow the formation of bicarbonate 
almost exclusively, and in addition many of these waters contain 
considerable free carbon dioxide. The amount of free and half-bound 
carbon dioxide in the zone of alteration seems disproportionately large 
in relation to the amount of hydrogen sulphide, even if the ready 
oxidation of hydrogen sulphide is taken into account. 

The apparent disparity between the total amount of carbon 
dioxide formed and the amount of sulphate removed may be due to 
the fact that all the carbon dioxide is not derived from the oxidation 
of hydrocarbons. Several reactions are known by which carbonate 
may be derived from inorganic sources. Hilgard 1 2 finds that a 
solution containing free carbon dioxide in the presence of sodium 
sulphate dissolves calcium carbonate and forms sodium bicarbonate 
and a precipitate of gypsum. This reaction would partly explain 
the disappearance of sulphate and the formation of carbonate, but 
it would not account for the formation of hydrogen sulphide. If it 
is assumed, however, that the hydrogen sulphide is derived through 
the reduction of sulphate, the presence of free carbon dioxide may 
be explained by the following reaction, first investigated by Bechamp : 3 

CaC0 3 + 2H 2 S = Ca(SH) 2 + H 2 0 + C0 2 . 

Under other conditions hydrogen sulphide may unite with calcium 
carbonate to form calcium sulphate and sulphur. 3 It is evident, 
therefore, that the disappearance of sulphate and the formation of 
carbonate may be the net result of several reactions. As the strata 
in the oil fields of the San Joaquin Valley do not contain much 
calcium carbonate, the reactions just discussed have probably not 
entered largely into the development of the chemical character of 
the waters, but the possibility that they have played some part 
should be duly considered. 

1 Hilgard, E. W., The geologic efficacy of alkali carbonate solution: Am. Jour. Sci., 4th ser., vol. 2, pp. 
100-107,1896. 

2 Bechamp, A., Recherches sur l’etat du soufre dans les eaux minerales sulfurees: Annales ctnmie et 
phys., 4th ser., vol. 16, p. 234,1869. 

3 Spezia, G., Sull’ origine del solfo nei giacimenti solfiferi della Sicilia, 1 orino, 1892. 




100 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

PRODUCTION OF GASES. 

Whatever the reactions controlling the character of the oil-field 
waters may be, it is clear that sulphide, free hydrogen sulphide, 
carbonate, bicarbonate, and free carbon dioxide are formed. The 
particular significance of the gases hydrogen sulphide and carbon 
dioxide will be briefly considered. 

Although the sulphide radicle is probably first formed during the 
reduction of sulphate, it is ordinarily so unstable that hydrogen 
sulphide may be considered the final product. As this gas is found 
in many of the waters above the oil measures, and as these waters 
still contain some sulphate, it is probable that they are undergoing 
alteration at the present time. The strong odor of hydrogen sulphide 
may readily cause overestimation of the amount present in a water. 
The greatest amounts that have come to the writer’s attention, which 
are reported in waters from the Eastside Coalinga field, do not exceed 
350 parts per million, and few waters carry more than 50 parts. As 
the complete reduction of 10 parts of sulphate would yield 3.5 parts 
of hydrogen sulphide, it is evident that either the sulphate in the 
upper waters is not all reduced directly to hydrogen sulphide or else the 
hydrogen sulphide is being removed from the solution nearly as 
rapidly as it is being formed. Some of it may unite with iron to 
form iron sulphide, which is precipitated. A small amount of hydrogen 
sulpiride has been found in some of the hydrocarbon gas, but the total 
quantity accounted for in this way is not great. 

As hydrogen sulphide readily oxidizes to sulphur, even under 
very feebly oxidizing conditions, considerable amounts of it are 
doubtless oxidized to sulphur and so removed by precipitation from 
the waters above the oil measures. 1 As the strata above the oil 
measures have not been examined for sulphur this hypothesis can 
not be definitely proved, but commercial deposits of sulphur have 
been found near the south end of the Sunset field, in sec. 21, T. 11 
N., It. 23 W., in pockets and fissures in the McKittrick formation, 
which includes the oil measures in the producing field near by. 
Most of the sulphur is amorphous, but some of it occurs as clear 
yellow crystals as much as a quarter of an inch in diameter. A 
steady flow of hydrogen sulphide is emitted from a pipe which has 
been driven a short distance into the ground near one of the prospect 
pits. A very interesting feature of this sulphur is its intimate mix¬ 
ture with hydrocarbon material, which seems to constitute 20 per 
cent or more of the amorphous substance. No oil or tar seeps are 
found in the immediate neighborhood of the sulphur deposits, but 
deposits of brea occur less than a mile away. Small deposits of 


1 The precipitation of sulphur by the oxidation of hydrogen sulphide is discussed in detail by Walter 
F. Hunt (Origin of the sulphur deposits of Sicily: Econ. Geology, vol. 10, pp. 543-579, 1915). 





CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 101 

disseminated sulphur are not uncommon along the western edges 
of the Coalinga and Midway-Sunset fields, and it seems probable that 
these accumulations have been derived from sulphate by the reducing 
action of hydrocarbons. 

The other important gaseous product of the reaction between 
sulphate and the hydrocarbons is carbon dioxide. As already 
stated, there is almost invariably sufficient carbonic acid to form 
bicarbonate exclusively in the waters in the zone of alteration, and 
in addition many of these waters contain a dissolved excess of free 
carbon dioxide. Unfortunately, the few determinations that have 
been made of the quantity of free carbon dioxide give no idea of the 
amount present in the water underground. The writer has seen 
several waters so heavily charged that they effervesced when they 
were brought to the surface, and the dissolved gas may cause some 
waters to rise or flow. Free carbon dioxide is present also in many of 
the modified waters above the zone of alteration, but it has not been 
observed in the normal waters, in many of which a deficiency of 
carbon dioxide and the consequent presence of some normal carbonate 
are observable. 

The hydrocarbon gas of many of the California fields contains a 
considerable proportion of carbon dioxide, much of which, in the 
writer’s opinion, has probably been formed in the same manner as 
the free, half-bound, and combined carbonic acid associated with 
the oil-field waters. In general, the gas in the shallower western 
portions of the Coalinga and Midway-Sunset fields contains more 
carbon dioxide than that in the deeper eastern portions. In other 
words, the natural gas near the outcrop generally contains more 
carbon dioxide than that several miles away. This is to be expected 
if the carbon dioxide is formed by the interaction of the sulphate 
water and the hydrocarbons, for most of the sulphate water enters 
the strata at their outcrops and it is therefore in this locality that the 
reaction should be most vigorous. The percentage of carbon dioxide 
in the gas generally ranges between 3 and 25, but the gas from a 
well about 600 feet deep in sec. 22, T. 19 S., R. 15 E., in the Eastside 
Coalinga field,'contains 49 per cent of carbon dioxide. As carbon 
dioxide is inert it acts as a diluent in natural gas and lowers its 
heating value. The following table shows analyses of gas from wells 
in the Coalinga, Midway, and Sunset fields. 1 Analysis 7 represents 
gas from the deep eastern part of the Midway field; it will be noted 
that the carbon dioxide is low in this gas, and a number of other 
analyses of gas from the same locality show still smaller amounts. 


1 A few other analyses are given by I. C. Allen and W. A. Jacobs (Physical and chemical properties of the 
petroleums of the San Joaquin Valley of California: U. S. Bur. Mines Bull. 19, p. 56,1912) 







102 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 


Analyses of natural gas from Coalinga, Midway, and Sunset fields, Cal. 



1 

2 

3 

4 

5 

6 

i 

Carbon dioxide. 

5.1 

11.1 

34.2 

20.0 

19.7 

20.0 

7.6 




.9 





Oxveren . 

1.1 


.3 

.0 

.0 

.0 

.0 

Methane. 

92.8 

88.0 

61.8 

74.7 

73.8 

62.5 

76.5 

Rthane . 



.7 

4.4 

5.7 

16.4 

15.2 

Nitrogen . 


.9 

2.1 

.9 

.8 

1.1 

.7 


.5 

.0 















99.5 

100.0 

100.0 

100.0 

100.0 

100.0 

100.0 

Heating value (British thermal units per cubic 








foot). 


937 

603 

904 

892 

971 

1,097 


Coalinga field: 

1. Well in sec. 11, T. 19 S., R. 15 E. Analyzed by Kern Trading & Oil Co. 

2. Several wells in sec. 25, T. 20 S., R. 14 E. Analyzed by U. S. Bureau of Mines. (Bur. Mines Bull. 

19, p. 56, 1912.) 

3. Well m sec. 36, T. 20 S., R. 14 E. Analyzed by Smith, Emery & Co. Authority, Associated Oil Co. 
Midway-Sunset fields (samples 4, 5, 6, and 7 collected by G. S. Rogers in July, 1914, and analyzed by G. A. 

Burrell, of the Bureau of Mines): 

4. Well 5, Hal e-McLeod Oil Co., sec. 8, T. 32 S., R. 23 E. 

5. Well 6, Chanslor-Canfield Midway Oil Co., sec. 31, T. 31 S., R. 23 E. 

6. Well 5, Spreckles Oil Co., sec. 32, T. 12 N., R. 23 W. 

7. Well 5, Honolulu Oil Co., sec. 6, T. 32 S., R. 24 E. 

I 

ALTERATION OF HYDROCARBONS BY WATER. 

Despite the close association of petroleum and water in most oil 
fields the chemical relations of the two have apparently never re¬ 
ceived much attention. Many oil men have developed from per¬ 
sonal observation opinions concerning the effect of water on pe¬ 
troleum, but these opinions differ widely and little attempt has been 
made to corroborate them in the laboratory. In fact, petroleum 
chemists have been occupied so largely in working out the complex 
constitution of petroleum and the processes of refining it that we 
know little of the effect on petroleum of any of the substances with 
which it comes in contact underground. The great differences be¬ 
tween petroleum in different regions are doubtless due largely to 
differences in the composition of the original organic matter and to 
differences in age and degree of metamorphism; but some of these 
broader differences, as well as most of the minor variations in the 
character of the oil from any one field, are probably due to the 
local action of natural agents. Of these oxygen and sulphur are 
probably among the most important. 

When oil is exposed to the air for some time it becomes dark, heavy, 
and viscous, and finally passes to asphalt. This change is due chiefly 
to the evaporation of the more volatile constituents but partly to 
oxidation. Thus, if hot air is passed through a so-called paraffin 
oil for several hours the oil becomes black and asphaltic. 1 Simi¬ 
larly, if solid paraffin or a paraffin oil is digested with sulphur it 
becomes black and asphaltic, 2 or if a light asphaltic oil of the type 

1 Jenney, W. P., On the formation of solid oxidized hydrocarbons resembling natural asphalts by the 
action of air on refined petroleum: Am. Chemist, vol. 5, p. 359, 1875. 

2 See Kohler, H., Die Chemie und Technologie der natiirlichen und kiinstlichen Asphalte, p. 119, Braun¬ 
schweig, 1904. 






































CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 103 

produced in the Buena \ ista Hills is used it also becomes heavier and 
more viscous and passes to a substance resembling solid asphalt. 
The chemical reactions involved in this change are probably of two 
kinds. A part of the sulphur may combine with certain oil con¬ 
stituents to form simple sulphur compounds or complex sulphur 
derivatives, another portion may unite with some of the hydrogen 
of the oil and pass off as hydrogen sulphide. By the loss of hydrogen 
a condensation or polymerization of the hydrocarbon molecules is 
effected, and this change is reflected in the increase in the gravity of 
the oil itself as it approaches solid asphalt. Oxygen acts in a similar 
way; some of it may be taken into combination to form complex 
acids or phenols and part of it may unite with the hydrogen of the 
oil to form water. 1 Oxygen has been determined in so few analyses 
of oil from the San Joaquin Valley fields that its relation to the 
gravity of the oil, except in a very broad way, is not known; but 
the percentage of sulphur has been determined in a great many 
samples and appears to bear a fairly constant relation to the gravity 
of the oil. If more than 0.75 per cent of sulphur is present the specific 
gravity of the oil is generally greater than 0.945 (18° Baume). The 
sulphur content of oils of 0.985 to 1.000 specific gravity (12° to 10° 
Baume) is usually 1 per cent or more, whereas that of oils of 0.875 
to 0.905 gravity (30° to 25° Baume) is generally less than 0.50 per 
cent. 2 

That oxygen and sulphur may be important agents in determining 
the character of petroleum is evident from the likelihood that the oil 
in its migration will encounter one or both of these common elements 
in some available form. Oxygen is probably the less important under 
ordinary conditions, but in some places the oil doubtless derives oxy¬ 
gen from oxygenated waters, and in others it may possibly be con¬ 
tributed locally by oxidizing agents such as manganese dioxide. The 
action of sulphur is probably more widespread, and sulphur is believed 
to be afforded abundantly by the reduction of the sulphate waters. 
There are other possible sources of sulphur, but they need not be con¬ 
sidered here. 

It is evident that in any one field the action of both oxygen and 
sulphur on the oil will be more or less localized, since ordinarily the 
quantity of these substances available is insignificant as compared 
with that of the petroleum. Most of the oil in the San Joaquin 

1 Mabery, C. F., and Byerly, J. H., The artificial production of asphalt from petroleum: Am. Chem. 
Jour., vol. 18, p. 141, 1896. See also Hausmann, J., and Pilat, S., Studien fiber die Oxydation der Petrol- 
kohlenwasserstoffe: Cong, internat. p^trole Compt. rend. sess. 3, p. 378,1907. 

2 Analyses of oil from the oil fields of San Joaquin Valley are given in the following publications: Arnold, 
Ralph, and Anderson, Robert, Geology and oil resources of the Coalinga district, Cal., with a report on the 
chemical and physical properties of the oils, by I. C. Allen: U. S. Geol. Survey Bull. 398, pp. 264-272, 1910. 
Allen,I. C.,and Jacobs, W. A., Physical and chemical properties of petroleums of the San Joaquin Valley 
of California: Bur. Mines Bull. 19,1912. Allen, I. C., Jacobs, W. A., Crossfield, A. S., and Matthews, R. R., 
Chemical and physical properties of the petroleums of California: Bur. Mines Tech. Paper 74,1914. 






104 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

Valley fields has migrated up from lower formations, and there is 
reason to believe that some of the variation in its composition and 
properties is the result of changes that have taken place during this 
migration. The free chemical energy of reacting substances and the 
time of contact are potent factors in chemical change, and these factors 
should be recognized in accounting for variations in the properties of 
oil that has migrated. An oil that is the first to traverse a given 
course comes in contact with reacting substances at their highest 
potential, and therefore becomes changed more radically than does 
the oil that follows it at the same rate. As soon as these reacting 
substances have become exhausted, then oil may pass them unaffected. 
Again, oil that moves with extreme slowness and remains a very long 
time in contact with reacting substances may undergo changes just as 
marked as though it had moved more rapidly in a new channel. In 
general, therefore, that portion of the oil which migrated first or 
farthest will be the most altered. Moreover, the oil nearest the sur¬ 
face or nearest the outcrop of the oil-bearing zone may be further 
altered by fresh supplies of descending sulphate waters. Therefore, 
the oil around the upper edges of the main body should as a rule be 
the most altered or, in other words, the heaviest and most asphaltic. 

This reasoning is well borne out by the variations in the gravity 
of the oil in the valley fields. In the deeper portion of the Midway- 
Sunset field, for example, the specific gravity of the oil ranges between 
0.933 and 0.875 (20° and 30° Baume), but as the outcrop is ap¬ 
proached the oil becomes heavier and most of the wells nearest the 
outcrop produce oil of specific gravity about 0.985 to 0.972 (12° to 
14° Baume). A part of this difference is probably due to the escape 
of the more volatile constituents of the oil in the zone along the out¬ 
crop, but variation in gravity several miles away from the outcrop 
can hardly be explained in this way. Furthermore, as a general rule, 
to which there are local exceptions, the highest producing oil sand 
carries heavier oil than the sands below. In portions of the Coalinga, 
Midway, and Sunset fields the producing oil sands are overlain at a 
distance of several hundred feet by the tar-sand zone, which contains 
sands partly impregnated with a very heavy, viscous tar. Some of 
the sands in this zone carry water of the modified type (sulphur 
water), and most of the tar sands become water bearing farther down 
the dip. So far as the writer knows this very heavy tar has never 
been analyzed, but the analyses of several samples of oil of 0.993 • 
(11° Baume) gravity show about 1.15 per cent of sulphur, and it 
may be presumed that the tar carries at least as much as this. In a 
general way the tar-sand zone marks the farthest limit of migration 
of the oil. It has been observed that oil which has migrated for 
some distance into sands that lie in angular unconformity with the 


CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 105 


main oil zone generally becomes heavier with distance from the main 
body and finally passes to tar. Purely on the basis of field evidence, 
therefore, it would appear that among the important factors influ¬ 
encing the gravity of the oil are the distance that the oil has migrated, 
its present distance from the outcrop or its depth below the surface, 
and the extent to which it is or has been subject to contact with 
waters, especially meteoric (sulphate) waters. 

There seems little doubt therefore that the local variations in the 
character of the oil are in part, at least, due to the action of sulphur 
and probably also of oxygen. Sulphate waters descending from the 
surface are to a large extent altered in the zone of tar sands, and the 
tar itself is thereby rendered still more asphaltic. To some extent, 
therefore, the tar sands may be conceived as protecting the main 
body of oil in the sands below. The same process goes on near the 
outcrop, although how far descending meteoric waters have affected 
the main body of the oil since it attained its present position is a 
matter of conjecture. It seems more reasonable to suppose that the 
oil which migrated first and farthest was considerably altered by the 
water that had previously occupied the sands, and that most of its 
alteration took place before it had come to rest in its present position. 

SOLUBILITY OF PETROLEUM CONSTITUENTS IN WATER. 

Certain minor constituents of petroleum or natural gas are soluble 
in water and have been observed in oil-field waters from several 
regions. Aside from the scientific interest that attaches to these 
substances they may in some places be of practical use, for their 
presence in a water has been taken by some to indicate that the 
water has been closely associated with oil or gas. The petroleum 
constituents soluble in water are of two kinds—simple light hydro¬ 
carbons, such as methane, and complex hydrocarbon derivatives, such 
as the naphthenic acids. 

The solubilities of some of the simple gaseous hydrocarbons have 
been investigated, with the results shown in the following table. 
The solubility decreases with increasing temperature, and at 40° C. 
(104° F.) may be only two-thirds to three-fourths of the solubility 
at 20° C. (68° F.). The solubility is generally decreased by the 
presence of mineral salts in the water but is increased to some extent 
by pressure. 




106 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

Solubility of certain gaseous hydrocarbons in water. 


[At 20° C.and 760 millimeters pressure, except propane, which is at 17.8° C. and 753 millimeters pressure.) 


Name. 

Formula. 

Volumes 
soluble 
in 100 
volumes 
of water. 

Authority. 

\ 

Methane . 

CH<. 

3.31 

4.72 

6.50 

0 

12.2 

22.1 

Winkler.a 

Do. 

Lebeau. b 
Frankland. c 
Winkler.d 

Von Than.« 

Ethane. 

c 2 h 6 . 

Propane. 

C 3 H 8 . 

Butane. 

C 4 H 1 O. 

Ethylene . 

C 2 H 4 . 

Propylene . t . 

c 3 h 6 . 




a Winkler, L. W., Die Loslichkeit der Gase in Wasser: Deutsche chem. Gesell. Ber., Band 34, pp. 1417- 
1421,1901. 

b Lebeau, Paul, Sur quelques propri6t6s physiques du propane: Compt. Rend., vol. 140, pp. 1454-1456 
1905. 

cFrankland, Edward, Ueber die Isolirung der organischen Radicale: Annalen der Chemie, Band 71, 
p. 171, 1849. (Frankland states that butane is insoluble in water, but it is desirable that this early work 
be checked with the more refined methods now in use.) 

d Winkler, L. W., unpublished data cited by Landolt-Bornstein, Physikalisch-chemische Tabellen 
p. 604, 1905. 

« Von Than, Carl, Der Absorptions coefficient des Propylengases: Annalen der Chemie, Band 123, p 187 
1862. 

Methane and ethane are the predominating constituents of most 
natural gas, and water which has been in contact with gas is therefore 
likely to contain these hydrocarbons in solution. Propane has been 
found in some gas, but propane and butane are more commonly 
associated with light paraffin oil. Ethylene and perhaps propylene 
may occur in natural gas but are not common. 

The hydrocarbons dissolved in the California oil-field waters are 
doubtless chiefly methane and ethane. Their presence in the water 
flooding an oil well is of little value in determining the source of that 
water, as they are rapidly soluble and may be taken up by the water 
while it is being raised to the surface. Their presence in water from 
a wildcat well in which no oil or gas has yet been found might be 
taken merely as a suggestion of the proximity of petroleum, but 
certainly could not be considered conclusive evidence. Methane in 
particular is so widely distributed that its presence in a water has 
little significance; ethane and ethylene are more generally associated 
with petroleum deposits and therefore have somewhat greater diag¬ 
nostic value. The presence of propane would be still more significant, 
but as this hydrocarbon is not common in California oil or gas it 
would seldom be a factor in practical work. 

The more complex hydrocarbon derivatives that are soluble in 
water are chiefly compounds containing oxygen, the commonest of 
which are probably the naphthenic acids. All the waters near the 
oil zone in the San Joaquin Valley fields are alkaline, and the presence 
of organic acids may be determined by acidulating the water. Organic 
acids if present in moderate amounts appear as a milky precipitate, 
but in some waters are present in so large amount that they separate 
out in largo oily globules. Many of the waters near the oil measures 
or in the diatomaceous shale below respond to this reaction. 

























CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 107 

The naphthenic acids are the oxygen derivatives of the naphthenes 
(polymethylenes) and have tlie general formula C n H 2n _ 2 0 2 . These 
compounds were observed by Hell and Medinger 1 2 in 1874, and in 
1890 Aschan studied them in detail and gave them the name naph¬ 
thene carboxylic acids. The naphthenes are prominent constituents 
of much of the Russian, Galician, and Roumanian oil, and when such 
oil is exposed to the air, especially in sunlight, the acids tend to 
form. 3 These acids have been observed in waters associated with 
the Russian oil and have been studied by Kharitschoff, 4 who in recent 
years has published a number of papers on their properties and nature. 
Inasmuch as the naphthenes are, according to Mabery and Hudson, 5 
important constituents of the California and other American oils, it 
is probable that naphthenic acids are to be found in the water asso¬ 
ciated with these oils also. Fatty acids have been reported in oil-field 
waters by several of the earlier investigators, 6 but their identification 
has since been questioned. However, Thompson 7 has more recently 
reported fatty acids (probably oleic and palmitic acids) in the waters 
from wells in the Grosny district, Russia. Kharitschoff, 8 in waters 
from the same locality, reports carbonates of ammonia and the 
amines, and Schidkoff 9 reported in the oil itself small quantities of 
formic and oxalic acids. Hydroxyl derivatives of the nature of 
phenols have been reported in California and other oils, 10 and these 
compounds may also be present in the oil-field waters. However, 
the naphthenic and perhaps the fatty acids, which may be grouped 
under the general term petroleum acids, are probably the commonest 
petroleum derivatives in oil-field waters. In alkaline waters these 
acids are doubtless present as alkali salts rather than as free acids. 

So far as the writer knows, no attempt has been made to study or 
' even to determine quantitatively the petroleum acids in California 
oil-field waters, although, as already stated, several chemists have 
detected them qualitatively. It has been suggested that the presence 

1 Hell, C., and Medinger, E., Ueber das Vorkommen und die Zusammensetzung von Sauren im Roh- 
petroleum: Deutsche chem. Gesell. Ber., Band 7, pp. 1216-1223, 1874; Ueber die Oxydation der im 
Rohpetroleum enthaltenden Saure, C 11 H 20 O 2 : Idem, Band 10, pp. 451-456, 1877. 

2 Aschan, O., Ueber die in dem Erdol aus Baku vorkommenden Sauren von niedrigerem Kohlenstoff- 
gehalt: Deutsche chem. Gesell. Ber., Band 23, pp. 867-875, 1890; Band 24, pp. 2710-2724, 1891; Band 25, 
pp. 3661-3670, 1892. 

3 Ostrejko, R. A., Influence of sunlight and air on petroleum products (abstract): Soc. Chem. Ind. 
Jour., pp. 26, 345, and 645, 1896. 

4 Kharitschoff’s papers appeared mostly in Russian journals, but adequate summaries of them are 

given in the Chemical Abstracts and in the Journal of the Chemical Society of London. 

& Mabery, C. F., and Hudson, E. J., On the composition of California petroleum: Am. Acad. Arts and 
Sci. Proc., vol. 36, pp. 255-283, 1901. 

6 Potilitzin, A., Zusammensetzung des die Erdol begleitenden und aus Schlammvulkanen ausstromenden 
Wassers (abstract): Deutsche chem. Gesell. Ber., Band 16, p. 1395-a, 1883. 
i Thompson, A. B., Oil fields of Russia, p. 93, London, 1908. 

s Kharitschofi, K. V., Ueber die Analyse des Wassers aus den Bohrlochem des Grosnyschen Bezirkes: 
Chem. Centralbl., vol. 78, p. 295, 1907. 

» Schidkoff, N., Acid content of Grosny petroleum and derivatives (abstract): Soc. Chem. Ind. Jour., 
vol. 18, p. 360, 1899. 

Mabery, C. F., The composition of American petroleum: Am. Chem. Soc. Jour., vol. 28, p. 426,1906. 







108 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

or absence of these substances in a water may serve to determine 
whether the water is from a horizon very near the oil zone or far 
above it, but the validity of such a distinction obviously depends 
on the ease and rapidity with which the water can dissolve the 
acids from the petroleum. If top water leaking down behind the 
casing and mixing with the oil can dissolve petroleum acids before 
it is pumped out such a distinction would be entirely misleading. 
It is probable that the chemical character of the water has much 
to do with its ability to dissolve the acids. In refining oil the 
naphthenic acids are usually removed by the addition of caustic 
soda, for the alkali salts of these acids are readily soluble in water. 
The alkaline-earth salts of the naphthenic acids are somewhat less 
soluble. Hence, when alkali carbonate water of the type associated 
with the hydrocarbons in many parts of the San Joaquin Valley 
fields is brought in contact with oil containing petroleum acids it 
may be inferred that alkali naphthenates or soaps will readily form 
and go into solution. The oil-field brines, however, contain no 
alkali carbonates and only small quantities of alkaline-earth car¬ 
bonates, and the rapid formation of organic salts in these waters 
would probably be less common. In washing the ether solutions of 
the acids Holde x uses a concentrated solution of sodium sulphate in 
order to avoid dissolving the acids. As the acids are thus prac¬ 
tically insoluble in strong solutions of sodium sulphate, and as. 
most of the shallower oil-field waters are essentially solutions of 
sodium sulphate and chloride, it seems probable that brief contact 
of a shallow water with the oil would not suffice for the solution 
of these organic compounds. 

It may therefore be inferred that alkali carbonate waters which 
occur near the oil zone or which have been mixed with the oil before 
being raised to the surface, are most likely to contain salts of the 
petroleum acids; that brines may or may not contain these com¬ 
pounds, and that normal top waters rarely contain them unless they 
have been allowed to stand in contact with the oil for some time. 
When oil stands exposed to the air, as in a sump, it is probable that 
naphthenic acids are formed by oxidation; hence most sump water, 
especially if it be of the alkali carbonate type, probably contains 
petroleum acids. Water which has been intimately mixed with oil 
in the form of an emulsion is also more likely to contain them. For 
these reasons it would seem that the value of petroleum acids as 
indicators of the original position of a water with respect to the oil 
zone is open to question. The rapidity with which they are extracted 
by different types of water must be investigated before their evidence 
can be positively relied on. 


1 Holde, D., and Mueller, E., The examination of hydrocarbon oils, p. 232, New York, 1915. 





VALUE OF WATER ANALYSES TO OIL OPERATOR. 109 

Those who desire to examine oil-field waters for petroleum acids 
may find the following simple test of value. This test, which depends 
on the green color of copper naphthenates, was recently devised by 
Kharitschoff . 1 

The water to be tested is first acidulated with hydrochloric acid and well shaken 
with benzine, which extracts all organic acids, leaving all the sulphur behind. The 
benzine solution is then separated, repeatedly washed with warm water and filtered. 
The filtrate is added with a few cubic centimeters of a solution of copper sulphate and 
three or four drops of piridine or of a strong ammoniac solution, and the mixture is well 
shaken. A green coloration of the benzine on top of the testing tube shows the pres¬ 
ence of petroleum acid in the tested water, and the degree of coloration allows to 
judge of its quantity. 

VALUE OF WATER ANALYSES TO THE OIL OPERATOR. 

Much of the foregoing discussion of the chemical relations of water 
and oil is necessarily hypothetic, owing to the unfortunate lack of 
chemical experimentation bearing on the subject, and although for 
the sake of simplicity only one broad hypothesis has been presented 
it is realized that discussion is by no mean's closed. However, the 
conjectural nature of the conclusions advanced do not affect the 
validity of the main facts presented in this paper, which relate to 
the composition and chemical properties of the oil-field waters them¬ 
selves. There is no question that the normal ground waters are 
very different from those close to or below the oil measures, and that, 
broadly speaking, the horizon at which a water occurs is indicated 
by its chemical composition. According to the few analyses pub¬ 
lished the water associated with the oil in most oil fields is character¬ 
ized by the absence of sulphate, but probably in few regions do these 
waters present such marked contrast with the shallower waters as in 
the San Joaquin Valley, in which sulphate is especially abundant. 
It would seem peculiarly unfortunate therefore if the operators do 
not take advantage of these favorable conditions to use the character 
of the water as a general index of its horizon, for the need for some 
easy means of determining the source of the water flooding a well is 
yearly becoming more pressing. 

The gradations between the strong sulphate waters near the sur¬ 
face and the sulphate-free water near the oil measures have already 
been described. There is little question that in all the San Joaquin 
Valley fields the same order of change from the surface downward is 
to be observed, but the total extent of the change and the point 
above the oil at which it becomes complete are subject to variation. 
In the Westside Coalinga field all the data at hand indicate that the 
alteration of the water is not complete until the oil measures are 
reached, whereas in the Midway and Sunset fields completely altered 


i Kharitschoff, K. V., Petroleum acids in boring waters: Petroleum Rev., vol. 28, p. 380, 1913. 





110 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

waters are found several hundred feet above the oil zone. In these 
fields, moreover, waters containing only small amounts of sulphate 
are found comparatively near the surface, and the change in the 
character of the water with depth is therefore less marked. It may 
be inferred by analogy that similar conditions exist in the Lost Hills 
fields and in the other structures of this type which are believed to 
contain oil. In the Eastside Coalinga field very different conditions 
prevail, and all gradations from a pure sulphate water to a pure car¬ 
bonate water may be observed. At the same time the waters near 
the oil measures in this field generally contain some sulphate, and 
may in fact contain more than the waters 500 feet above the oil in 
the Midway and Sunset fields. These local variations do not affect 
the broad principles involved, but they are evidently of great prac¬ 
tical importance, and only general conclusions can be drawn from an 
analysis until these variations have been worked out in the area in 
which the water occurs. 

In order to work out the detailed changes between successive 
water sands in each area it is necessary that as many reliable analyses 
as possible be placed on record. The analyses given in this report 
are sufficient to show the general type of the chemical changes that 
take place, but they are not intended to constitute a description of 
local conditions. It is believed by the writer that within small areas 
the chemical character of water from the same horizon is sufficiently 
constant to justify correlations on the basis of the analyses, and 
hence that when a sufficient number of analyses of reliable samples 
have been collected and made available for comparison the horizon 
of an unknown water may be closely estimated. Thus, one of the 
larger companies in the Midway field is making a practice of collecting 
water samples while drilling the well and preserving the samples, or 
analyses of them, for future reference. If the well later “goes to 
water ” a sample of this water is analyzed and the analysis is com¬ 
pared with those of the waters encountered while drilling. A marked 
difference in composition between the waters first above the oil 
measures and the water flooding the well is taken to indicate that the 
water flooding the well is from strata below the oil nr that it has in¬ 
vaded the oil sand at some other point and has migrated to the well. 
This use of water analyses is a matter of simple comparison and de¬ 
pends only remotely on the principles involved in the variation in the 
water as it approaches the oil zone. In the Midway-Sunset field, 
where variations in the character of the water are not as marked as in 
other areas and where a slight difference in sulphate content may 
indicate a difference in position of several hundred feet, it is probable 
that this method will be essential in the accumulation of an adequate 
amount of data regarding the character of the water in the 500 feet 
or so on either side of the oil measures. In the Westside Coalinga 





VALUE OF WATER ANALYSES TO OIL OPERATOR. Ill 

field, however, fairly accurate estimates of the horizon of the waters 
can often be made on the basis of much less complete information. 

A factor which might militate against the success of this method 
in some regions is the possibility that a flow of water may change in 
character during lapse of time. When large quantities of water are 
removed by one well from a sand, water which may be different in 
composition is drawn toward the well from distant parts of the sand. 
The variation in character is most noticeable when the water with¬ 
drawn from the sand is salty and is being replaced by fresh water, 
which enters at the outcrop. Replacement by fresher water is of 
course most likely to take place in shallow sands, and in general 
little or no change in character takes place in flows from deep-lying 
sands. 1 This condition should hold especially in the oil fields, where 
usually no effort is made to produce water from the deeper sands 
and where their normal contents are therefore disturbed as little as 
possible. Changes in the concentration of the water may be ob¬ 
served, but the relative proportions of the several constituents prob¬ 
ably remain about constant, unless a considerable circulation is 
set up. 

The variations in the chemical character of the waters as oil is 
approached may also be used as a guide in wildcatting. In many 
prospect holes this evidence will probably be put to little practical 
use, for marked changes in the character of the water generally do 
not occur more than a few hundred feet above the first showings of 
tar or gas. Contingencies may readily arise, however, in which 
corroborative evidence of the probable presence of hydrocarbons 
below will be of value. For example, if a well reaches a depth of 
4,000 feet, and there encounters water very similar in character to 
that near the surface, and if at this point serious drilling difficulties 
involving great extra expense are encountered, the advisability of 
proceeding farther may be questioned. On the other hand, if the 
water at this depth contains no sulphate the prospect of finding oil 
a short distance below is decidedly more encouraging. It should be 
pointed out, however, that commercial quantities of oil or gas may 
not be necessary to produce an altered water. The writer has a 
number of analyses of water from prospect wells of the Standard 
Oil Co. in southern California, and although the water in all the 
wells which produced commercial quantities of oil is sulphate-free, 
that in several wells which gave only shows of oil also contains only 
small amounts of sulphate. However, in other unsuccessful wells 
the deep water, so far as the tests have been applied, contains more 
sulphate than the water near the surface. As far as commercial 
quantities of the hydrocarbons are concerned it seems probable that 

1 Sanford, Samuel, Saline artesian waters of the Atlantic Coastal Plain: U. S. Geol. Survey V ater-Supply 
Paper 258, p. 85,1910. 






112 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

when the evidence of the water is adverse it can be taken with more 
assurance than when it seems favorable. 

The remarks in the preceding paragraph concerning the use of 
water analyses in prospecting are intended to apply only to the San 
Joaquin Valley region. If the writer’s conception of the principles 
involved is correct, then, as oil is approached, similar variations in 
the character of the water should occur also in other regions. So 
far as is known, however, these variations have never been studied 
elsewhere, and in advance of definite knowledge it must be recognized 
that an extension of this method to other regions is based wholly on 
theory. 

In using water analyses to predict conditions in unexplored dis¬ 
tricts a complication arises from the fact that the rate of change in 
the composition of the waters and the distance above the oil measures 
at which sulphate disappears are different in different areas. The 
chemical character of the oil itself may be involved in these differ¬ 
ences, but observations in the San Joaquin Valley fields indicate 
that stratigraphic and structural conditions are of prime importance. 
If the bedding is sufficiently irregular to permit transverse migration 
of either the water or the hydrocarbons the water may be con¬ 
siderably altered some distance above the main body of oil. If the 
course of the water is influenced by fault planes or unconformities 
the variations in its character may be irregular. Structural con¬ 
ditions influencing the freedom of circulation are also very important, 
for they determine in a measure the quantity of sulphate that is 
brought down to be acted upon by the oil. In other words, a given 
quantity of oil may be able to reduce the sulphate in a large body of 
stagnant water, but if the water is in circulation and fresh supplies of 
sulphate are constantly penetrating to the oil measures the reduction 
may not be complete. Hence, if structural conditions in the area 
in question are such as to prevent circulation, a high concentration 
of chloride is to be expected; sulphate will probably be present in 
rather small amount even in the shallower waters and may be entirely 
absent in the waters several hundred feet above the oil zone. If, on 
the other hand, the circulation is relatively free and the outcrop of 
the beds not far distant, chloride will probably be low and a consid¬ 
erable concentration of sulphate may be present in the waters close 
above the oil measures. 

In comparing the analyses of two different waters all the constitu¬ 
ents must be taken into account; their relative values as criteria 
for comparison have been indicated elsewhere. General comparisons 
may be made of analyses reported in hypothetic combinations, but 
much more satisfactory results are obtained if the analyses are recal¬ 
culated and the comparison made on the basis of the reacting values 
of the radicles themselves. The practice of attempting to estimate 


SUMMARY OF CONCLUSIONS. 


113 


the horizon of a water on the basis of a partial analysis can not be too 
strongly condemned. Some oil men have attempted to compare 
waters simply by tasting them, but it is evident that only the roughest 
distinctions can be made in this way, and the analyses given in this 
report suffice to show that the amount of salt a water contains is no 
indication of its horizon, except perhaps very locally. Others have 
used hydrogen sulphide as a means of distinguishing or correlating 
waters, chiefly because this constituent can readily be detected by its 
odor or by its ability to, darken a silver coin immersed in the water. 
As many top waters contain hydrogen sulphide, whereas the waters 
below the oil contain it only in some localities along the border of 
the fields, this simple test may sometimes be of value. Owing to 
the ease with which hydrogen sulphide is oxidized, however, it can 
not be regarded as a very stable constituent of the water and its 
value as a criterion for comparison is limited. A complete analysis 
is always the most satisfactory. In conclusion, it may be reiterated 
that an analysis is of no value in comparison unless the sample is 
properly taken and the analytical work accurately performed, for 
otherwise very misleading conclusions may be drawn. 

SUMMARY OF CONCLUSIONS. 

Water-bearing sands are generally encountered above, below, and, 
in many places, in the oil measures in the oil fields bordering the San 
Joaquin Valley. The strata are lenticular and the correlation of 
individual beds except within limited areas is impracticable. The 
high pressure of the water in many of the sands renders it difficult 
to prevent the water from invading the oil sands and thus greatly 
reducing their productivity. 

Some of the ground waters are as salty as ocean water, but others 
are fresh. This difference is believed to be the result of difference in 
freedom of circulation, which is controlled chiefly by the geologic 
structure. Where the structure prevents free circulation the ground 
water is salty, but where it does not and circulation is relatively free 
meteoric water has entered the beds and replaced much of the strong 
chloride water originally present. The ground water near the surface 
and near the outcrops of the beds is comparatively fresh, but the 
content of chloride generally increases with depth and with distance 
from the outcrop. The deeper waters trapped in structural troughs, 
like the Midway syncline, closely resemble ocean water in most 
respects and are believed to be only slightly altered connate water or 
fossil sea water. 

The surface waters and shallow ground waters and also the deeper 
ground waters outside the oil fields on the west side of the San Joa¬ 
quin Valley contain much sulphate. In the oil fields, however, the 
content of sulphate decreases with depth and ground waters near and 


60439°—Bull. 653—17-8 



114 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

in the oil measures are practically free from sulphate. This decrease 
in sulphate is attended by a corresponding increase in carbonate, and 
in districts in which chloride is not abundant the waters near the oil 
measures are nearly pure carbonate waters. Where chloride is the 
predominating acid radicle, even in the shallower waters, carbonate 
is unimportant, and the chief change in character with depth is due 
to the disappearance of the sulphate. Sulphide and hydrogen sul¬ 
phide appear near the horizon at which sulphate begins to decrease 
and are present in many of the waters above the oil measures, but the 
complete disappearance of the sulphate and of the sulphide are coin¬ 
cident. The amount of sulphide in the deeper waters is roughly pro¬ 
portional to the amount of sulphate in the waters directly above 
them, or nearer the surface. 

Calcium and magnesium predominate in many of the surface wa¬ 
ters, but sodium and potassium greatly predominate in the deeper 
waters. Most of the waters associated with the oil are therefore 
variously proportioned mixtures of solutions of alkaline carbonates 
and chlorides, the proportion of carbonate depending chiefly on the 
extent to which meteoric water is able to enter at the outcrop. Be¬ 
sides the change in character with depth the oil-field waters therefore 
exhibit progressive variations with distance from the outcrop, the 
predominantly carbonate waters being found near the outcrop and 
the predominantly chloride waters farther away. The final stage in 
this gradation is represented by the very salty waters, which are 
believed to be comiate. Coincident with these changes in composi¬ 
tion is a great increase in the total amount of dissolved solids. 

The decrease of sulphate, appearance of sulphide, and increase of 
carbonate in the waters as the oil zone is approached all point to 
reactions between the oil-field waters and constituents of the oil or 
gas. It is probable that sulphate is reduced to sulphide by certain 
oil constituents whose carbon is simultaneously oxidized to products 
which eventually yield carbonate, though the stages involved in these 
reactions and the conditions under which they take place are not yet 
understood. These reactions not only alter the character of the 
waters but they also produce the gases carbon dioxide and hydrogen 
sulphide. Carbon dioxide, presumably thus produced, occurs in the 
natural gas of these fields in amounts ranging from 5 to more than 
30 per cent. The greatest proportions of carbon dioxide are usually 
found in gas near the outcrop, where sulphate water can most readily 
enter the beds and where the reaction would naturally be vigorous. 
A large part of the hydrogen sulphide formed is probably changed to 
sulphur, some of which apparently reacts again with the oil to make 
it heavier and more asphaltic. It is significant that the oils contain- 


SUMMARY OF CONCLUSIONS, 


115 


ing the largest proportion of sulphur are in general the heavy oils 
close to the surface or to the outcrop of the oil measures. 

The marked differences in chemical composition between the waters 
close to the oil measures and those at higher levels are believed to 
afford a means of estimating the position of a water with respect to 
oil. This knowledge should be useful in determining the source of 
water flooding an oil well and also in prospecting for oil or gas. The 
distance above the oil measures at which the marked changes in the 
composition of the water occur depends on local conditions, which 
remain to be determined in each field. The order of change, however, 
has been found to be uniform, and it is believed that the use of analy¬ 
ses in estimating the position of a water with regard to the oil will 
prove valuable to those engaged in the exploitation and development 
of the California oil fields. 


List of water analyses. 


Owner. 

Designation. 

Location. 

Analy¬ 
sis No. 

Page. 

Sec. 

T. 

R. 

Coal in ga field: 







Aenrn Oil Co 

Well No. 1. 

2 

20 S. 

14 E. 

46 

73 

Amerinn.n Petroleum Co.. 

Well No. 2 N. 

30 

20 S. 

15 E. 

61 

76 


Well No. 21. 

30 

20 S. 

15 E. 

62 

* 76 

A<jsor.in.ted Oil Co_ _. 

Water well. 

36 

20 S. 

14 E. 

74 

81 


Oil well. 

36 

20 S. 

14 E. 

75 

81 


Oilwell. 

36 

20 S. 

14 E. 

76 

81 


Oil well. 

36 

20 S. 

14 E. 

77 

81 

Assnniatnd Pipeline Co . 

Water well. 

18 

20 S. 

15 E. 

10 

59 

California Oil & Gas Co . 

Water well No. 1. 

6 

21 S. 

15 E. 

12 

59 

California Oilfields (Ltd.). 

Well No. 2. 

10 

19 S. 

15 E. 

15 

62 


Well No. 16. 

14 

19 S. 

15 E. 

16 

62 


Well No. 16. 

26 

19 S. 

15 E. 

27 

66 


Well No. 37. 

27 

19 S. 

15 E. 

35 

69 


Well No. 5. 

29 

19 S. 

15 E. 

34 

69 


Well No. 1. 

34 

19 S. 

15 E. 

40 

70 


Well No. 15. 

34 

19 S. 

15 E. 

36 

69 


W T ell No. 31. 

34 

19 S. 

15 E. 

41 

70 


Oilwell. 

2 

20 S. 

15 E. 

39 

69 

Coalinpa TTomestaPe Oil Co. . .. 

Water well. 

26 

20 S. 

14 E. 

29 

66 

Coalmine .. . 


26 

20 S. 

14E. 

80 

81 

T) ia 7. Creep 



19 S. 

14 E. 

2 

57 

tTern Trading &. Oil Co.. 

Oilwell. 

35 

19 S. 

15 E. 

37 

69 


Oilwell. 

11 

20 S. 

15 E. 

42 

70 


Oilwell. 

13 

20 S. 

14 E. 

19 

62 


Water well. 

15 

20 S. 

14E. 

43 

70 


.Oilwell. 

25 

20 S. 

14 E. 

22 

63 


Oilwell. 

25 

20 S. 

14 E. 

23 

63 


Oilwell. 

25 

20 S. 

14 E. 

24 

63 

T.ns Gatos Creep 



20 S. 

14 E. 

1 

57 

T.neille Oil Co 

Wells Nos. 1 and 2. 

6 

21 S. 

15 E. 

64 

76 

Nevada Petroleum Co.. 

Well No. 1. 

20 

20 S. 

15 E. 

63 

76 


Well No. 3. 

30 

20 S. 

15 E. 

20 

62 

OznrP Oil Co 

Well No. 3. 

26 

20 S. 

14 E. 

21 

62 

Premier Oil Co. 

Well No. 3. 

24 

19 S. 

14 E. 

18 

62 

"Reeord Oil Co 

Well No. 5. 

22 

19 S. 

15 E. 

17 

62 

Santa Rosa Oil & Development 

Water well. 

12 

21 S. 

HE. 

30 

66 

CO. 

RAution Ravati Oil Co 

Well No. 5. 

7 

20 S. 

15 E. 

60 

76 

Standard Oil Co. 

Domengine No.l. 

27 

18 S. 

15 E. 

78 

81 


Dom engine No.l. 

27 

18 S. 

15 E. 

79 

81 


Water well No. 3 . 

28 

19 S. 

ih E , 

8 

59 


Oilwell. 

36 

19 S. 

15 E. 

38 

69 


Water well No. 2 . 

36 

19 S. 

15 E. 

9 

59 

f Trei Hat*< 5 Oil Co 

Water well . 

24 

20 S. 

14 E. 

11 

59 

Union Oil Co . 

La Vista No. 4 . 

4 

20 S. 

15 E. 

28 

66 














































































116 


OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL 
List of water analyses —Continued. 


Owner. 

Designation. 

Location. 

Analy¬ 
sis No. 

Page. 

Sec. 

T. 

R. 

Midway and Sunset fields: 







AOil Co __ _.. 

Well No. 1. 

35 

31 S. 

22 E. 

65 

76 


Pioneer Midway No. 7- 

30 

21 S. 

23 E. 

50 

73 


Well No. 2. 

32 

31 S. 

23 E. 

49 

73 

August Water Co. 

California Amalgamated 

35 

32 S. 

23 E. 

26 

63 


Well No. 2. 







California Amalgamated 

31 

32 S. 

24 E. 

71 

77 


Well No. 3. 






"Rlt.tArwat.ftr CtaaV 


29 

UN. 

24 W. 

5 

57 

CrASAins Oil Co . 

Water well No. 6. 

25 

32 S. 

23 E. 

68 

77 

Crocker Rprine r . 


18 

31 S. 

22 E. 

4 

57 

Oonoral Potrolonm Co. 

Carnegie water well. 

9 

31 S. 

22 E. 

44 

70 


Water well No. 2. 

15 

32 S. 

23 E. 

67 

77 

Good Roads Oil Co . 

Well No. 14. 

12 

11 N 

24 W. 

73 

77 

TTonolnln Oil Co . 

Well No. 6. 

10 

32 S. 

24 E. 

51 

73 

"R’ern County Land Co 

Spring. 

23 

10N. 

23 W. 

6 

57 

1Cam Tradiriv A Oil Co 

Oil well . 

31 

12 N. 

23 W. 

57 

74 

Mavs Consolidator! Oil Co.. 

Well No. 6. 

28 

31 S. 

23 E. 

47 

73 

Midway Basin Oil Co.. 

0 il well. 

28 

31 S. 

24 E. 

32 

66 

Midway NorttiArn Oil Co. 

Water well. 

32 

12 N. 

23 W. 

14 

59 


Well No. 5. 

32 

12 N. 

23 W. 

58 

74 

M. J.&M. M. Oil Co. 

Well M. J. 6. 

36 

12 N. 

24 W. 

56 

74 

North American Oil Consoli- 

Well No. 71. 

16 

32 S. 

23 E. 

66 

76 

dated Co. 







Potter Oil Co. 

Well No. 2. 

15 

31 S. 

22 E. 

45 

70 

San Emigdio Creek a ... 





7 

57 

Standard Oil Co. 

Well No. 6. 

22 

31 S. 

23 E. 

48 

73 


Well No. 6. 

12 

32 S. 

23 E. 

25 

63 


Well No. 7. 

12 

32 S. 

23 E. 

53 

74 


Well No. 2. 

14 

32 S. 

23 E. 

70 

77 


Well No. 3.. 

20 

32 S. 

24 E. 

54 

74 


Well No. 3. 

24 

32 S. 

23 E. 

69 

77 

• 

Well No. 1. 

28 

32 S. 

24 E. 

55 

74 


Well No. 1. 

30 

32 S. 

24 E. 

81 

83 


Well No. 1. 

30 

32 S. 

24 E. 

82 

83 

Stratton Water Co. 

Well No. 3. 

7 

32 S. 

23 E. 

31 

66 

Sunset Monarch Oil Co. 

Well F. 

26 

12 N. 

24 W. 

72 

77 

Sunset Security Oil Co. 

Well No. 1. 

29 

11 N. 

23 W. 

59 

74 

Union Oil Co.... 

Diamond well No. 2. 

13 

11 N. 

24 W. 

53 

74 

Western Water Co. 

Water wells. 

5 

31 S. 

25 E. 

13 

59 

Other fields: 






Associated Oil Co. 

Well No. 33. 

18 

30 S. 

21 E. 

89 

85 


Well No. 3. 

13 

26 S. 

20 E. 

88 

85 

Frazers Spring. 


2 

30 S. 

21 E. 

3 

57 

Kern River b . 





83 

85 

Lindsay Incorporated Oil Co.... 

Well No. 1. 

7 

27 S. 

21 E. 

87 

85 

Petroleum Development Oil Co. 

Oil well. 

4 

29 S. 

28 E. 

86 

85 

Standard Oil Co. 

Water well. 

5 

28 S 

27 E 

S4 

85 


Well No. 1. 

27 

28 S. 

27 E. 

85 

85 

Ocean water. 





52 

73 









a San Emigdio Land Grant 


b Bakersfield. 

















































































INDEX. 


A. Page. 

Absorptive capacity of various rocks. 13 

Acids, petroleum, nature and occurrence of. 106-109 

petroleum, test for. 109 

Acknowledgments for aid. 6-7 

Alkalies, distribution and significance of.41-42 

Alkaline earths, distribution and significance 

of..42-43 

Alkalinity, primary and secondary, use of the 

terms. 38 

Alteration of hydrocarbons by water.102-105 

Alteration of waters by hydrocarbons. 50-52, 

93-102 

Altered waters, analyses of. 67-77, S5 

limits of. 52 

position of. 52 

use of term. 51 

Aluminum, distribution and significance of.. 46 

Aluminum and iron, method of determining.. 32 

Ambrose, W. A., acknowledgment to. 7 

Analyses of waters, alphabetical list of, by 

fields.115-110 

need for.'.. 7-8 

sources of.. 40 

value of, to the oil operator.109-113 

Analysis, constituents to be determined by... 31-32 
statement of..32-35 

B. 

Bacteria, decomposition of sulphate by.94-96 

Barium, occurrence of. 94 

Bicarbonate, reported as carbonate. 47 

See also Carbonate. 

Boron, occurrence of. 47 

“Bottom water,” use of term. 17 

Brine, analyses of.71-74,85 

effect of adding primary alkaline water to. 90 

Brines, average concentration of. 90 

Bromine, occurrence of.47,94 

Brown, W. E., acknowledgment to. 7 

Buena Vista Hills, ground water in.28-29 

Bush, R. D., acknowledgment to. 7 


C. 

Calcium, ratio of, to magnesium in different 


types of water.43,92 

See also Alkaline earths. 

Calcium carbonate, action of carbon dioxide 

and sodium sulphate on. 99 

Calcium sulphate, reduction of. 96 

Carbon dioxide, formation of.101,114 

Carbonate, distribution and significance of... 6, 

44-45,114 

formation of.98-99 

source of.. H 

substitution of, for sulphate.88-89 


Page. 

Carbonate-sulphate ratio, use of..48-49 

Chloride, distribution and significance of.... 44,114 

variation in.86-87 

Circulation, conditions governing. 14 

Classification of waters. 41-52 

Coalinga oil field, ground waters in.26-27 

location and importance of. 8 

Colloids, presence of.31-32 

Comparison of waters, criteria for.4S-49 

Concentration of waters, variation in. 40 

Conclusions.5-6,113-115 

Connate water, characteristics of.. 50 

mixing of meteoric waters with. 86 

predominance of alkalies in. 42 

probable migration of. 61 

Cretaceous rocks, oil in. 10 

Crumpton, T. J., acknowledgment to. 7 

D. 

Dearin, J. H., acknowledgment to. 7 

Depth of water-bearing rocks.. 16 

Dinsmore, S. C., acknowledgment to. 7 

Dole, R. B., acknowledgment to. 7 

Drainage of San Joaquin Valley. 9 


E. 

Eastside Coalinga field, ground waters in.... 27 


position of. 26 

“ Edge water, ” use of term. 17 

Elliot, J. E., acknowledgment to. 7 

Equivalents for analytical units. 33 

F. 

Faulkner, E. O., acknowledgment to. 7 

Fellows, Midway field, partial analyses of oil- 

well waters from. 87 

Flow of water, change in character of. Ill 

G. 

Gas pressure, nature of.18-19 

Gases, production of.100-102 

Gaylord, E. G., acknowledgment to. 7 

Geography of San Joaquin Valley. 9 

Geology of San Joaquin Valley. 9-11 

Gravity of oil, variation of, with depth-104-105 

Greer, W. A., acknowledgment to. 7 

Ground water, altered, analyses of. 67-77,85 

depth to. 16 

lower limit of. 16 

mineral matter dissolved in. 20 

modified, analyses of. 64-66,81 

normal, analyses of. 58,59-63 

reversed type of, analyses of. 67-70,85 

salt, origin of.20-23 

time when entrapped.24-25 


117 




















































































118 


INDEX 


H. Page. 

Hardness, chemical basis of. 38 

Head of ground waters, decrease of. 17-18 

low, reasons for. 15-16 

range of. 17 

Hern, J. J., acknowledgment to. 7 

Hydrocarbons, alteration of, by water.102-105 

alteration of waters by.93-102 

reduction of sulphate by.96-97 

solubility of, in water. 105-109 

Hydrogen sulphide, detection of. 113 

formation of. 45,46,100 

occurrence of, in ocean water.95-96 

oxidation of.95,98 

II ydrostatic pressure, nature of. 18 

I. 

Iodine, occurrence of. 47,94 

Ionic form, conversion of analyses to.34-35 

conversion of analyses from, to reacting 

values.35-37 

Iron, distribution and significance of. 46 

Iron and aluminum, method of determining. 32 

J. 

Jurassic rocks, nature and distribution of.... 10 

K. 

Kern River oil field, ground water in. 29 

location and importance of. 8 

water pressure in. 19 

Kern Trading & Oil Co., water analyses from. 40 
Kharitschoff, K. V., test for petroleum acids 

by. 109 

Kirwan, M. J., acknowledgment to. 7 

L. 

Lenses, sand, three classes of. 14,15-16 

Lombardi, M. E., acknowledgment to. . 7 

Lost Hills field, ground water in. 27 

M. 

McKittrick field, ground water in. 27-28 

Magnesium, ratio of, to calcium in different 

typ es of water. 43,92 

See also Alkaline earths. 

Magnesium sulphate, reduction of. 97 

Meteoric water, characteristics of. 50 

concentration of. 90 

Methane, inactivity of. 97 

solubility of. 106 

source of, in waters. 106 

Midway-Sunset oil field, ground water in_28-29 

location and importance of... 8 

range of altered water in. 7-8 

Midway Valley, ground water in. 28 

Migration of oil, changes during. 104 

Mineral solids, amount of. 47 

Minerals, presence of, in ground water.29-30 

Mixed type of ground water, analyses of.. 75-77,85 

relations of. 88-93 

Modified water, limits of. 52 

position of. 51-52 

use of term. 50-51 

N. 

Naphthenic acids, nature and occurrence of. 106-109 

Natural gas, composition of. 101-102 

Nitrate, occurence of. 47 


Page. 

Normal water, limits of. 52 

position of.-. 51 

use of term. 50 

O. 

Ocean water, analysis of. 73 

reduction of sulphate in...95-96 

O’Donnell, T. A., acknowledgment to. 7 

Oil, indications of, from character of wa¬ 
ters. 6,109-113 

pressure of water on. 12 

source of. 10 

See also Hydrocarbons. 

Oil fields, location and importance of. 8 

Oil wells, top water from, analyses of. 58,59-63 

Orcutt, W. W., acknowledgment to. 7 

Organic matter, omission of, from analyses.. 47-48 
Outcrop, changes in waters with distance 

from.90-91 

Oxygen, action of, on oil. 102-105 

P. 

Pack, R. W., acknowledgment to. 6 

Paine, Paul, acknowledgment to. 7 

Palmer, Chase, acknowledgment to. 6-7 

Petroleum constituents, solubility of, in 

water. 105-109 

Petroleum Development Co.’s well, field 

assay of water from. 84 

Potassium, method of determining. 32 

ratio of, to sodium in different types of 

water.92,93 

retention of, by soils. 42 

See also Alkalies. 

Pressure. See Head. 

Propane, significance of, in waters. 106 

Properties, reactive, determination of. 37-40 

R. 

r, use of the symbol.*. 36 

Radicles, factors for calculating. 34 

recalculation of. 34-35 

Reacting values, calculation of.35-37 

Reaction, properties of, determination of_37-40 

Reaction coefficients, use of.36-37 

Relations areal, of the types. 86-93 

vertical, of the types. 78-85 

Requa, M. L., acknowledgment to. 7 

Reversed type, use of term. 51 

Rock pressure, nature of. 18 

S. 

Salinity, chloride, and sulphate, ratio of. 40 

Salinity, primary and secondary, use of the 

terms. 38 

Salt, distribution of, in ground waters. 6,113 

influence of, in the genesis of petroleum... 25 

Salt waters, origin of..... 20-23,26 

Samples of water, collection of..8,30-31 

Sands, dry, danger of water from. 15 

dry, nature of. 15-16 

oil, geologic structure of. 10-11 

oil and water, relative positions of. 16-17 

unfounded distinctions between. 13 

texture of, influence of. 13 

water below oil in. 17 

water, correlation of... 16 

Shallow-well waters, analyses of. 58,59,85 

Silica, distribution and significance of. 47 


Silver coin, detection of hydrogen sulphide by 113 




































































































INDEX 


119 


Page. 

Sodium, method of determining. 32 

ratio of, to potassium in different types of 

water.92,93 

See also Alkalies. 

Sodium sulphate, reduction of, experiments 

on. 97 

Sodium sulphide, occurrence of. 46 

Stabler, Herman, acknowledgment to. 6-7 

Standard Oil Co., water analyses from. 40 

Starke, E. A., acknowledgment to.... 7 

Structure, relation of, to distribution of salt 

water.23-25 

Sulphate, content of, in ocean water. 44 

distribution and significance of. 6,43-44,113-114 

gradation of, in depth. 109-110 

reduction of.93-98 

source of.11-12 

substitution of carbonate for. 88-89 

Sulphate-free waters, occurrence of.93-94 

Sulphide, distribution and significance of_45-46 

oxidation of. 98 

Sulphur, action of, on oil.102-105 

formation of, from hydrogen sul¬ 
phide. 95,98,99,100-101 

Sulphur waters, position of. 46 

Surface waters, analyses of. 55-57,85 

Synclines, salt water in.23-24 


T. Page. 

Temperature, range of. 19 

use of, in prospecting. 19-20 

Tertiary formations, nature and distribution 

of.,. 10 

“Top water,” use of term. 17 

Tough, F. B., acknowledgment to. 7 

Types of ground water, areal relations of_86-93 

vertical relations of. 78-85 

V. 

Van der Linden, B. R., acknowledgment to. 7 
Volatile matter, omission of, from analyses-. - 47-48 

W. 

Wallace, W. M., acknowledgment to. 7 

Water, connate, kinds of. 21 

connate, use of term.21-23 

determination of source of. 6,8 

difficulty with, in oil wells. 5 

ground, circulation of. 11-12 

pressure of 1,000-foot column of. 15 

salt, association of, with petroleum.25-26 

distribution of, governed by structure 23-25 

Wells, water, causes of pressure in. 18 

Westside Coalinga field, constancy of condi- 

tionsin. 7 

ground waters in. 27 

position of. 26 


4 

O 


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